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UNITED STATES
SECURITIES AND EXCHANGE COMMISSION
WASHINGTON, D.C. 20549

FORM 10-K

[X] ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d)
OF THE SECURITIES EXCHANGE ACT OF 1934

FOR FISCAL YEAR ENDED DECEMBER 31, 2000

[ ] TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d)
OF THE SECURITIES ACT OF 1934

FOR THE TRANSITION PERIOD FROM TO

COMMISSION FILE NO. 0-22483

SEVEN SEAS PETROLEUM INC.
(EXACT NAME OF REGISTRANT AS SPECIFIED IN ITS CHARTER)

CAYMAN ISLANDS 73-1468669
(State or other jurisdiction of (I.R.S. Employer
incorporation or organization) Identification No.)

5555 SAN FELIPE, SUITE 1700
HOUSTON, TEXAS 77056
(Address of principal executive offices) (Zip Code)

Registrant's telephone number, including area code: (713) 622-8218

Securities registered pursuant to Section 12(b) of the Act

NAME OF EACH EXCHANGE
TITLE OF CLASS ON WHICH REGISTERED
-------------- -------------------
Ordinary shares -- par value $0.001 per share American Stock Exchange

Securities registered pursuant to Section 12(g) of the Act

None

Indicate by check mark whether the registrant (1) has filed all reports
required to be filed by Section 13 or 15(d) of the Securities Exchange Act of
1934 during the preceding 12 months (or for such shorter period that the
registrant was required to file such reports), and (2) has been subject to such
filing requirements for the past 90 days. Yes [X] No [ ]

Indicate by check mark if disclosure of delinquent filers pursuant to Item
405 of Regulation S-K is not contained herein, and will not be contained, to the
best of registrant's knowledge, in definitive proxy or information statements
incorporated by reference in Part III of this Form 10-K or any amendment to this
Form 10-K. [ ]

As of March 30, 2001, there were 37,836,420 outstanding shares of the
registrant's ordinary shares (also called "common shares"), par value $0.001 per
share. The aggregate market value of the common shares held by non-affiliates of
the registrant (treating all executive officers and directors of the registrant
and their respective affiliates for this purpose as if they may be affiliates of
the registrant) was approximately $111.8 million on March 30, 2001, based upon
the closing sale price of the common shares on such date of $3.40 per share on
the American Stock Exchange as reported by The Wall Street Journal.

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TABLE OF CONTENTS TO FORM 10-K

PAGE
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PART I

Item 1. Business 3
Item 2. Properties 10
Item 3. Legal Proceedings 17
Item 4. Submission of Matters to a Vote of Security Holders 18

PART II

Item 5. Market for Registrant's Common Equity and Related
Stockholder Matters 19
Item 6. Selected Financial Data 19
Item 7. Management's Discussion and Analysis of Financial Condition
and Results of Operation 20
Item 7a. Quantitative and Qualitative Disclosures about Market Risk 27
Item 8. Financial Statements and Supplementary Data 28
Item 9. Changes in and Disagreements with Accountants on Accounting
and Financial Disclosure 48

PART III

Item 10. Directors and Officers of the Registrant 48
Item 11. Executive Compensation 49
Item 12. Security Ownership of Certain Beneficial Owners and
Management 52
Item 13. Certain Relationships and Related Transactions 53

PART IV

Item 14. Exhibits, Financial Statement Schedules, and Reports on
Form 8-K 54

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PART I

ITEM 1. BUSINESS

OVERVIEW AND HISTORY

Seven Seas Petroleum Inc. ("Seven Seas") was incorporated under British
Colombia law on February 3, 1995. On June 29, 1995, Seven Seas amalgamated with
Rusty Lake Resources Inc. Rusty Lake was formed January 31, 1993, under Ontario
law, when Lithium Corporation of Canada, Limited joined Stockgold Resources Inc.
We continued Seven Seas as a Yukon Territory, Canada corporation in August 1996.
In March 2001, we continued Seven Seas as a Cayman Islands exempted company
limited by shares. Because we are devoting substantially all of our efforts to
establishing a new business, we are a development stage company under the SEC's
accounting rules. See "Risks Related to our Business -- We have a limited
operating history" and "-- We have historical operating losses."

We currently have working interests in six association contracts in
Colombia: (1) Dindal, (2) Rio Seco, (3) Deep Dindal, (4) Cristales, (5)
Rosablanca and (6) Tapir. We relinquished the Montecristo association contract
in early 2001. The Dindal and Rio Seco association contracts cover areas that
contain the Guaduas Oil Field.

We acquired our initial 15% interest in the Dindal and Rio Seco association
contracts in Colombia from GHK Company Colombia in 1995. Upon acquiring our
Dindal and Rio Seco interests, we participated in drilling the El Segundo 1-E
well, resulting in the discovery of the Guaduas Oil Field. In 1996, we acquired
an additional 36.7% interest in both association contracts for $153.1 million of
our securities, based on the closing stock price on the date of the acquisition.
We acquired the interest when we acquired 100% of GHK Company Colombia and
Esmeralda LLC, and 63% of Cimarrona LLC. On March 5, 1997, we acquired 100% of
the outstanding voting stock held in Petrolinson, S.A. for $18.6 million of our
securities, based on the weighted average of the closing prices for 30 day
periods before and after the letter of intent was signed. The principal asset
owned by Petrolinson, S.A. is a 6% participating interest in the association
contracts. As consideration for the 6% participating interest in the association
contracts, we issued to the sole shareholder of Petrolinson, S.A. 1,000,000
common shares of Seven Seas. This 6% interest was carried through exploration by
the other 94% participating interest parties.

In our 1999 Form 10-K and subsequent U.S Securities and Exchange Commission
filings, we outlined three scenarios for moving forward with the development of
the Guaduas Oil Field. Scenario 1 assumed that Empresa Colombiana de Petroleos,
the Colombian national oil company also known as Ecopetrol, participated in the
development of the Guaduas Oil Field. Scenario 2 assumed Ecopetrol did not
participate in the development of the field, but authorized Seven Seas and our
partners to proceed with development on a sole-risk basis. Sole-risk means that
Seven Seas and our partners pay 100% of development costs and retain all
revenues from production after the 20% Colombian royalty deduction. Ecopetrol
has the right to start participating in development at any time subject to Seven
Seas and partners' right to recover 200% of the development costs spent since
Ecopetrol's decision not to participate plus certain exploration costs. Scenario
2 also assumed that together with our partners we would proceed to develop the
field as proposed to Ecopetrol (i.e. construct a pipeline and drill development
wells for production of 20,000 BOPD to 30,000 BOPD). Like Scenario 2, Scenario 3
assumed that Ecopetrol would elect not to participate, but assumed that we would
modify our development program as proposed to Ecopetrol by postponing the
construction of the pipeline and development drilling.

After Ecopetrol elected not to participate in the development on May 23,
2000, together with our partners, we elected to proceed sole-risk under Scenario
2. In previous filings, including last year's Form 10-K, we stated that if we
proceeded under Scenario 2, we expected to commence pipeline production
approximately one year after Ecopetrol made its election. As of the filing date
of this report, we are on schedule to complete the pipeline by mid-year 2001.

For a more complete discussion of our association contracts, see "Properties
- -- Colombian Properties -- Dindal and Rio Seco association contracts," "-- Deep
Dindal association contract," "-- Cristales association contract," "--
Rosablanca association contract" and "-- Tapir association contract."

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SEVEN SEAS PETROLEUM INC. CORPORATE STRUCTURE

Following is a diagram of our corporate structure. We own 100% of all of our
subsidiaries.

[CHART]

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OUR CURRENT STRATEGY

Our strategy for 2001 includes the continued development of the Guaduas Oil
Field and new exploration on our Colombian properties.

DEVELOPMENT

We are currently constructing a 36-mile pipeline that will connect the
Guaduas Oil Field to international oil markets via Colombia's existing pipeline
infrastructure. The pipeline will have an initial throughput capacity of
approximately 25,000 barrels of oil per day (BOPD), expandable to approximately
40,000 BOPD with additional investment. We are also constructing production
facilities for production of approximately 25,000 BOPD. Both the pipeline and
production facilities are scheduled for completion in mid-2001. The gross costs
of the pipeline and the production facilities are $24 million, our share of
which is approximately $13.8 million.

When the pipeline and production facilities are complete, we believe that
initial pipeline production, which will be generated by existing productive
wells, will be approximately 8,000 BOPD to 10,000 BOPD. We recently agreed with
our Guaduas Oil Field partners to a two-year development well drilling program
that provides for the drilling of nine development wells and one injector over
the course of 2001 and 2002. We believe these wells will increase pipeline
production from its initial rates to approximately 25,000 BOPD. In 2001, we plan
to drill four of these nine development wells and the one injector well at a
gross cost of approximately $22 million, our share of which is $13 million. The
gross cost of the entire 2001--2002 development well program is estimated to
cost $44 million, our share of which is $25 million.

EXPLORATION

We plan to drill three exploration wells in 2001:

1. Subthrust exploration well to test the subthrust Dindal prospect at an
estimated gross cost of $15 million ($15 million net to us)

2. Santa Fe - 1 on the Rosablanca association contract at a gross cost of
$1.0 million ($1.0 million net to us)

3. Tres Pasos 16 well to test the west-side of the Guaduas Oil Field
structure at an estimated gross cost of $5.5 million ($3.0 million net
us).

In summary, in 2001 we plan to complete the construction of the pipeline
and production facilities for the Guaduas Oil Field, drill four development
wells and one injector well on the Guaduas Oil Field and drill three exploration
wells on our Colombian properties. The estimated gross costs of this development
and exploration strategy in 2001 are $68 million, our share of which is
approximately $46 million.

Our ability to fully implement our exploration and development strategy is
subject to 1) securing financing for our share of the costs, 2) timely receiving
required environmental permits, 3) contracting the required oil and gas services
and equipment, and 4) completing the Guaduas--La Dorada pipeline and commencing
pipeline utilization. For additional information on our 2001 strategy, see "Item
7. Management's Discussion and Analysis of Financial Condition and Results of
Operation - Our Current Strategy".

FINANCING OUR DEVELOPMENT

Under the terms of our $110 million senior notes, we are allowed to incur
indebtedness that could be secured and senior to the senior notes, not to exceed
the greater of (i) $25 million, or (ii) the sum of 100% of our cash and cash
equivalents, plus 100% of our receivable from Ecopetrol and plus 30% of our
discounted future net revenues from proved oil and gas reserves prepared in
accordance with the rules of the United States Securities Exchange Commission.
As of December 31, 2000 the maximum permitted amount of secured borrowing was
approximately $130.3 million. Based on discussions we have had with banks and
other institutions, we believe we can borrow a substantial amount of the cost of
putting the pipeline on production at a rate of between 8,000 BOPD and 10,000
BOPD. In such event, we could secure the additional indebtedness with our share
of the property. The senior notes also allow us to borrow an additional $10
million for project financing, e.g., pipeline and production facilities. We
believe that once the pipeline is built to sustain production at a rate of
between 8,000 BOPD and 10,000 BOPD, additional funds can be borrowed from the
potential lenders referenced above to finance a significant portion of the costs
necessary for development wells, flow lines and facilities to bring pipeline
production to 25,000 BOPD. We cannot be certain that additional sources of
financing will be available when needed or will be available on acceptable
terms. For more information about our financing plans, see "Management's
Discussion and Analysis of Financial Condition and Results of Operation -
Financing Our Current Strategy" and "- Liquidity and Capital Resources."

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executive officer of Seven Seas. Mr. Hefner received remuneration of $62,500 for
his guarantee. The loan bears interest at an annual rate of the Prime Rate plus
.75%, and interest is payable monthly until the loan is due in full on April 1,
2002. Seven Seas intends to use these funds for working capital and plans to
replace, without penalty, this non-convertible loan with the proceeds from a
larger financing planned for 2001.

RISKS RELATED TO OUR BUSINESS

In addition to the other information set forth elsewhere herein, the
following factors relating to Seven Seas should be carefully considered when
evaluating the company. This document includes "forward-looking statements"
within the meaning of the federal securities laws. All statements included
herein other than statements of historical fact are forward-looking statements.
Such forward-looking statements include, without limitation, the statements in
"Business" and "-- Management's Discussion and Analysis of Financial Condition
and Results of Operations," regarding Seven Seas' financial position, estimated
quantities of reserves, business strategy and plans and objectives for future
operations. Forward-looking statements herein generally are accompanied by words
such as "anticipate," "believe," "estimate," "project," "potential" or "expect"
or similar statements. Although we believe that the expectations reflected in
such forward-looking statements are reasonable, no assurance can be given that
such expectations will prove correct. Factors that could cause Seven Seas'
results to differ materially from the results discussed in such forward-looking
statements are discussed in "Risk Factors" and elsewhere herein. All
forward-looking statements included herein and therein are expressly qualified
in their entirety by the cautionary statements in this paragraph.

WE HAVE A LIMITED OPERATING HISTORY.

We commenced our operations in 1995 and have only a limited operating
history. Accordingly, we have limited historical financial and operating
information upon which to base an evaluation of our performance. Our prospects
must be considered in light of the risks, expenses, delays and difficulties
frequently encountered by companies in the early stages of development.

WE HAVE HISTORICAL OPERATING LOSSES.

Since the date of our inception through December 31, 2000, we have incurred
cumulative losses of $115.1 million. Our only production, as of December 31,
2000, has been our share of the approximately 1.2 million barrels of oil (0.5
million net to us) produced by the Guaduas Oil Field. We do not expect to have
uninterrupted production transported through pipeline prior to mid-2001.
Therefore, estimates of proved reserves and the level of future production
attributable to such reserves are difficult to determine. We cannot assure you
of the volume of recoverable reserves. Our business will continue to require
substantial expenditures. We cannot be certain that we will achieve or sustain
profitability or positive cash flows from operating activities in the future.

WE HAVE SUBSTANTIAL INDEBTEDNESS AND DO NOT HAVE ENOUGH REVENUES TO PAY OUR
DEBTS.

As of December 31, 2000, we had $110 million of 12 1/2% senior notes due
2005 and had entered into a $10 million loan agreement with Stillwater National
Bank and Trust Company N.A. Under certain circumstances, we may, or our
subsidiaries may, become further indebted. This much debt could pose substantial
risks to our business. The indebtedness may require us to use available funds
for payment of principal and interest instead of further developing our
properties. The debt could also inhibit our ability to raise additional capital.
It is possible that we will not have enough cash flow from our operations to pay
the principal and interest on our debt. See "Management's Discussion and
Analysis of Financial Condition and Results of Operation -- Liquidity and
Capital Resources."

OIL AND GAS PRICES WILL IMPACT OUR COMPANY

The market prices for oil and natural gas historically have been volatile
and are likely to continue to be volatile in the future. Oil and natural gas
prices may fluctuate in response to relatively minor changes in supply of and
demand for oil and natural gas, market uncertainty and a variety of additional
factors that are beyond our control. Decreases in oil and natural gas prices
will adversely affect our future revenues, results of operations and cash flows.
Additionally, decreases in oil and natural gas may impede our ability to raise
additional capital.

WE HAVE NOT HAD ANY SIGNIFICANT INCOME-PRODUCING PROPERTY UNTIL RECENTLY.

We are a development stage company under the U.S. Security and Exchange
Commission's accounting rules because we are devoting substantially all of our
efforts to establishing a new business and have produced no significant revenue
from the business. We did not have any significant income-producing property
until we began trucking production in August 2000. We are currently selling our
share of approximately 4,000 to 6,000 BOPD. Our principal assets are in the
early stages of exploration and development. Since the date of our inception
through December 31, 2000, we have incurred cumulative losses of $115.1 million.
Because we continue to explore and develop, we expect to continue to incur
losses until production from the Guaduas Oil Field occurs in quantities
sufficient to cover operating expenses. Assuming we can borrow at an acceptable
rate, we expect the amount of our debt to increase until production increases
enough to cover our operating expenses.

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ANY CASH FLOW WE EXPERIENCE MAY BE USED TO PAY OUR EXISTING DEBTS AND WE MAY NOT
HAVE THE CASH FLOW WE NEED FOR OTHER PURPOSES.

Any cash flow generated from our operations will likely be used to pay our
debt. As a result, we may not have the cash flow available for other purposes.
Additionally, our debt may affect our ability to finance our future operations
and capital needs.

IN ORDER TO MARKET PRODUCTION, WE WILL NEED PRODUCTION FACILITIES AND PIPELINES.

We cannot market our full production capacity without proper production
facilities and pipelines. We depend on the availability and capacity of
gathering systems, pipelines, compression and production facilities. We must
have adequate storage, separation and reinjection facilities. If these
facilities are not available or they are not large enough, we could have to shut
in producing wells, which means we would temporarily stop production from some
wells even though the wells are capable of producing oil. We also could have to
delay or discontinue our development plans. In December 2000 and January 2001,
we signed construction contracts for the pipeline and the production facilities.
We expect the pipeline and production facilities to be complete in mid-2001. See
"Business -- Our Current Strategy" and "Management's Discussion and Analysis of
Financial Condition and Results of Operation -- Our Current Strategy."

COLOMBIAN ENVIRONMENTAL LAWS HAVE DELAYED OUR OPERATION IN THE PAST AND MAY DO
SO AGAIN IN THE FUTURE.

Colombian environmental laws require us to get an environmental permit or
approval before we conduct seismic operations, drill wells or construct
pipelines. Our operations have been delayed in the past while we tried to get
environmental permits. Our operations could be delayed again for the same
reason. Failure to get the necessary licenses and permits may also prevent us
from getting alternative financing. During 2000, total environmental costs
attributable to our Colombian properties were $0.28 million gross ($0.16 million
net to Seven Seas).

POLITICAL AND ECONOMIC UNCERTAINTY IN COLOMBIA COULD WORSEN AT ANY TIME AND OUR
OPERATIONS COULD BE DELAYED OR DISCONTINUED.

Our business is subject to political and economic risks, including:

o loss of revenue, property and equipment as a result of unforeseen events
like expropriation, nationalization, war and insurrection;

o risks of increases in import, export and transportation regulations and
tariffs, taxes and governmental royalties;

o renegotiation of contracts with governmental entities;

o changes in laws and policies governing operations of foreign-based
companies in Colombia;

o exchange controls, currency fluctuations and other uncertainties arising
out of foreign government sovereignty over international operations;

o laws and policies of the United States affecting foreign trade, taxation
and investment; and

o the possibility of being subject to the exclusive jurisdiction of
foreign courts in connection with legal disputes and the possible
inability to subject foreign persons to the jurisdiction of courts in
the United States.

We have experienced an incident of guerrilla activity at one of our well
locations; however, our operations were not materially disrupted by such
activity. We do not know how guerrilla activity will affect us in the future, or
what steps, if any, the Colombian government may take in response to guerrilla
activities.

IF WE DO NOT SATISFY THE WORK REQUIREMENTS OF OUR ASSOCIATION CONTRACTS, THE
COLOMBIAN GOVERNMENT MAY TERMINATE ALL OR PART OF THE CONTRACTS.

Our Colombian association contracts have certain work requirements. For more
information on the specific contract terms and obligations, see "Properties --
Colombian Properties". We may not be able to satisfy our contractual
obligations. If we do not comply with the work requirements of the association
contracts, or successfully renegotiate the terms, Ecopetrol may terminate all or
part of one or more of our contracts.

OUR PLANS AND STRATEGY WILL CHANGE AS CONDITIONS DICTATE.

We are still a development stage company. Our ability to make plans and
forecasts is affected by numerous factors, many of which

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are beyond our control. As an example, we did not meet our announced schedule
for 2000. See "Business -- Our Current Strategy" and "Management's Discussion
and Analysis of Financial Condition and Results of Operation -- 2000 In Review."

THE U.S. HAS IMPOSED IN THE PAST, AND MAY IMPOSE IN THE FUTURE, ECONOMIC AND
TRADE SANCTIONS AGAINST COLOMBIA.

The United States has imposed economic and trade sanctions against Colombia
in the past, and may impose sanctions against Colombia in the future. Every
year, the president of the United States reviews designated foreign countries
for certification, including Colombia, and decides whether those countries have
cooperated with the United States to prevent drug trafficking. In 1995, 1996,
1997 and 1998, the president found that Colombia had not taken sufficient steps
to prevent drug trafficking and denied certification. As a result of Colombia's
failure to receive U.S. certification, the U.S. imposed the following sanctions:

o withholding all bilateral economic assistance;

o blocking loans from the Export-Import Bank of the United States and the
Overseas Private Investment Corporation; and

o voting against multilateral assistance to Colombia in the World Bank and
the InterAmerican Development Bank.

Although Colombia received certification in February 1999, March 2000, and
February 2001, if the United States imposes sanctions against Colombia again, we
may not be able to get the financing we need to develop our Colombian
properties. Sanctions by the United States could also cause Colombia to
retaliate against us by nationalizing our Colombian assets.

OUR OPERATIONS ARE CONCENTRATED IN COLOMBIA.

Our oil and gas properties are concentrated in Colombia. All of our proved
reserves are located in the capital state of Cundinamarca. As of December 31,
2000, all of our proved reserves were attributable to the Guaduas Oil Field. Due
to our concentration in and reliance on such operations for our future cash
flow, if our operations in Colombia were adversely affected, we would experience
a material adverse effect.

MARKETING

During 2000, we sold all of the oil we produced from the Guaduas Oil Field
to Refinerie del Nare and Ecopetrol.

REGULATION

GENERAL

Our operations are affected by political developments and laws and
regulations in the areas where we operate. In particular, oil and gas production
operations and economics are affected by:

o price controls;

o tax laws and other laws related to the petroleum industry, and changes
in those laws;

o changing administrative regulations; and

o the interpretation and application of existing regulations.

Legislative and administrative regulations regarding the oil and gas
industry change periodically. These changes occur for a variety of political,
economic, environmental and other reasons. Many different governmental
departments and agencies issue rules and regulations that are binding on the oil
and gas industry. Some of these rules and regulations carry substantial
penalties for any violation. The regulatory burden on the oil and gas industry
increases our cost of doing business.

All of our operations are affected by extensive environmental laws and
regulations in Colombia. These laws and regulations set standards regulating
health and environmental quality. They also establish penalties and other
liabilities for any violations. Some of the laws and regulations require the
violating party to remediate current and former facilities and off-site
locations. Additionally, special provisions may be appropriate or required in
environmentally sensitive areas of operation, such as where our Colombian
interests are located and where other independent producers of oil and gas have
faced significant liability resulting from environmental claims. Specifically,
our Colombian operations are governed by a number of ministries and agencies.
Our operations are governed by Ecopetrol, the Ministry of Mines and Energy and
the Ministry of the Environment, among others.

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Among other things, these regulations govern currency, imports and exports,
taxation and environmental controls. The regulations also specify:

o the extent to which properties may be acquired or relinquished;

o permits required for drilling wells and for the spacing of those wells;

o permits for developing and operating the field and pipeline
transportation systems;

o measures required for preventing the waste of oil and gas resources; and

o rates of production and sales prices to be charged to purchasers.

ENVIRONMENTAL MATTERS

Our Colombian operations are subject to a variety of environmental laws and
regulations. These environmental laws and regulations govern the discharge of
certain materials into the environment and the disposal of oil and gas waste.
They also are designed to protect human health and environmental quality. On the
federal level, the Ministry of Environment regulates all activities that could
adversely impact Colombia's environment and natural resources. The Ministry of
Environment requires specific environmental licenses for various oil and gas
exploration and production activities. Individual licenses are issued only upon
completion of a detailed environmental impact study. In the past, we have
experienced delays in obtaining our federal environmental licenses. We have also
experienced delays in getting other local environmental permits that are
required for expanding our Colombian operations. We may continue to experience
these kinds of delays in the future.

Despite these delays, we obtained the environmental licenses required for
our development activities for the Guaduas Oil Field in July 2000. We have also
received the licenses we need for production and development drilling
activities. See "Property - Colombian Properties - Production facilities,
gathering and pipeline systems for the Guaduas Oil Field."

We are currently waiting for environmental permits to drill exploration
wells on the Rosablanca association and Deep Dindal association contracts.

Environmental laws and regulations could result in substantial costs and
liabilities in the future. Significant liability could be imposed on us for
damages, clean-up costs and/or penalties for discharges into the environment. We
could also be liable for environmental damage caused by the previous owners of
our property or for non-compliance with environmental laws or regulations. This
kind of liability could have a material adverse effect on our operations. During
2000, total environmental costs attributable to our Colombian properties were
$0.28 million gross ($0.16 million net to Seven Seas).

We cannot predict what environmental legislation or regulations will be
enacted in the future. We also cannot predict how existing or future laws or
regulations will be administered or enforced. Compliance with stricter laws and
regulations, or the more vigorous enforcement of environmental policies, could
require us to make material expenditures for the installation and operation of
systems and equipment for remedial measures. Any of these scenarios could have a
material adverse effect on Seven Seas.

COLOMBIAN FOREST RESERVE

Two mutually overlying forest reserves existed in an area corresponding to
the Dindal Association Contract, one prior to and another subsequent to the
signing of this contract. The first forest reserve corresponds to a national
reserve declared in 1981 and enlarged in 1985, that sets limits to economic
activities within the reserve area. The national forest reserve does not
prohibit oil and gas activities within the reserve area. However, Seven Seas
must apply for an environmental license with the Colombian Ministry of
Environment to conduct operations within the forest reserve area.

The second forest reserve corresponds to a reserve declared by the
municipality of Guaduas in 1998, forbidding oil-related activity in the
mentioned reserve's area. The municipality of Guaduas subsequently revoked this
reserve through the Land Use Plan that adopted the national forest reserve as
the only existing reserve.

ENVIRONMENTAL PENALTIES

In March 2000, we paid a fine of approximately $223,000 to the Ministry of
Environment in connection with a resolution issued against GHK Company Colombia
by the Ministry of Environment in which it declared GHK Company Colombia to be
in violation of a 1997 decree in connection with the construction of the El
Segundo 7-E well location. We have filed an appeal for a reversal of the
resolution. We believe that we have corrected the environmental violations
claimed by the Ministry of Environment; however, the appeal process can take up
to two years. The El Segundo 7-E location has been restored and we currently
have no drilling activities planned at this location.

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COMPETITION

We encounter competition from other oil and gas companies in all areas of
our operations, including the acquisition of producing properties. Our
competitors in Colombia include major multi-national integrated oil and gas
companies and both local and multi-national independent oil and gas companies.
Many of our competitors are large, well-established companies with substantially
larger operating staffs and greater capital resources than we have and which, in
many instances, have been engaged in the oil and gas business for a longer time.
Such companies may be able to offer more attractive terms in obtaining contracts
for exploratory prospects and secondary operations and to pay more for
productive properties and exploratory prospects and to define, evaluate, bid for
and purchase a greater number of properties and prospects than our financial or
human resources permit. Our ability to acquire additional properties and to
discover reserves in the future will be dependent upon our ability to evaluate
and select suitable properties and to consummate transactions in this highly
competitive environment, as well as our ability to obtain adequate capital.

EMPLOYEES

As of December 31, 2000, we had 73 full-time employees, including
geologists, geophysicists, engineers and other employees. Seven Seas is not
subject to any collective bargaining agreement, and we believe that our
relationship with our employees is good.

ITEM 2. PROPERTIES

GENERAL OVERVIEW

Our Colombian operations are focused on the Guaduas Oil Field, located in
the capital state of Cundinamarca in central Colombia, approximately 60 miles
northwest of Bogota. The Guaduas Oil Field is located in a 109,000-acre area
defined by the Dindal and Rio Seco association contracts. The village of Guaduas
lies within the Dindal and Rio Seco association contract blocks and provides
infrastructure for the local economy, which is primarily agrarian in nature. The
area is accessible by the main road between Bogota and Medellin and the
Colombian Caribbean coast. We are the operator and own a 57.7% working interest
in the Guaduas Oil Field before Colombian government participation. As the
operator of the field, we exercise direct supervision over all field operations,
including drilling and production. The other interest owners are Cimarrona LLC
(9.4%) and Sociedad International Petrolera S.A., known as Sipetrol, the
international exploration and production subsidiary of the Chilean national oil
company (32.9%). Collectively we are known as the "Associates". As of December
31, 2000, the Ryder Scott Company Petroleum Consultants estimated Seven Seas'
net proved reserves attributable to the delineation of 12,821 acres of the
Guaduas Oil Field were 47.9 million barrels with a present value (discounted
continually over the expected life of the production at 10% per annum) of $
394.1 million.

We also have a 100% interest in the Deep Dindal, Cristales and Rosablanca
association contracts and a 19.19% interest in the Tapir association contract.
Additional information about each of these contract areas is provided later in
this section.

COLOMBIAN PROPERTIES

DINDAL AND RIO SECO ASSOCIATION CONTRACTS - GUADUAS OIL FIELD

The Dindal and Rio Seco association contracts cover adjoining areas of
approximately 109,000 acres that contain the Guaduas Oil Field. The Dindal
association contract has an effective date of March 23, 1993, and the Rio Seco
association contract has an effective date of August 22, 1995. Both association
contracts provided for a six-year exploration period followed by a maximum
22-year production period, with partial relinquishments of acreage, excluding
commercial fields, required at the end of the sixth year of each contract. The
Dindal exploration period has ended and we have 21 years left on the contract to
produce the Guaduas Oil Field. Although the exploration period ended, Ecopetrol
recently postponed the required relinquishment of Dindal association contract
areas outside the Guaduas Oil Field and the five-kilometer buffer zone for as
long as the Deep Dindal association contract is in the exploration period. The
Deep Dindal association contract was issued in February 2001. See "--Deep Dindal
association contract."

We are obligated to drill one more exploration well on the Rio Seco
association contract area before the exploration period of that contract ends in
August 2001. At some point in the future, we may have to relinquish the smaller
of 50% of the contract areas or all lands that fall outside a five kilometer
buffer zone around the area designated to be the commercial field.

In May 2000, Ecopetrol elected not to participate in the development
and production of the Guaduas Oil Field. The Associates have elected to proceed
on a sole-risk basis pursuant to the terms of the Dindal and Rio Seco
association contracts. Ecopetrol retains the right to participate at a later
date subject to the Associates recovering 200% of the costs incurred since
Ecopetrol's May 2000 decision not to participate plus certain exploration costs.

Under the terms of the Dindal and Rio Seco association contracts, the
Associates pay 100% of all exploratory costs. As Ecopetrol elected not to
participate in the development and production of the Guaduas Oil Field, the
Associates will also pay 100% of the development costs.

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The Associates are required to pay a royalty of 20% of all hydrocarbon
production to the Colombian government. Because Ecopetrol elected not to
participate at this time, the remaining 80% of production is divided among the
Associates according to their proportionate interest in the association
contract. If Ecopetrol participates in the future, the remaining 80% will be
divided as follows:

o Dindal association contract - Of the remaining 80% of production,
Ecopetrol will receive 50% and the Associates will receive 50% until
the contract area has produced in excess of 60 million barrels of oil,
after which point Ecopetrol's interest in production will increase on a
sliding scale. Such increases occur in 5% increments from 50% to 70% as
accumulated production from the contract area increase in 30 million
barrel increments from 60 million barrels to 150 million barrels.

o Rio Seco association contract - Of the remaining 80% of production,
Ecopetrol will receive 50% and the Associates will receive 50% until
the contract area has produced 60 million barrels of oil, after which
point Ecopetrol's interest will increase from 50% to 75% as the ratio
of accumulated income attributable to the Associates (less any expenses
reimbursed by Ecopetrol) increases from a one-to-one ratio to a
two-to-one ratio.

Under both contracts, if Ecopetrol does elect to participate, it would pay 50%
of the go forward development and operating expenses.

Our wholly owned subsidiary GHK Company Colombia serves as the operator of
the Guaduas Oil Field, pursuant to the terms of operating agreements between
Seven Seas, our subsidiaries and the other associates. GHK Company Colombia has
exclusive responsibility for operations within the budgets and work programs
approved by the executive committee and may demand payment in advance from each
party of its respective shares of estimated subsequent monthly expenditures.

Under the terms of a letter agreement dated September 11, 1992, as amended,
between GHK Company Colombia and Dr. Jay Namson, the holders of interests in the
association contracts, except for Petrolinson S.A., will be required to assign a
proportionately reduced 2% working interest in the Dindal association contract
and the Rio Seco association contracts to Dr. Namson after those interest
holders recover from production of 100% of all costs incurred in connection with
the exploration and development of the Dindal and Rio Seco association contract
areas since the completion of the first-year work obligations under the Dindal
association contract. Accordingly, when such costs have been recovered, we will
be required to assign to Dr. Namson 2% of 55% from our 57.7% interests.

DRILLING ACTIVITY ON THE RIO SECO AND DINDAL ASSOCIATION CONTRACTS

To date, thirteen wells have been drilled on the Dindal and Rio Seco
association contract areas. Seven of those wells are classified as oil and gas
wells. Five of the wells did not produce commercial amounts of oil and gas
during testing. One well remains to be tested.

The first well, the Escuela 1, which was drilled on the Dindal contract area
in 1994 prior to the time we acquired an interest in the association contract,
did not encounter the Cimarrona formation, the oil and gas reservoir of the
Guaduas Oil Field. It was plugged and abandoned as non-commercial.

The second well, El Segundo 1-E, was the discovery well of the Guaduas Oil
Field. The El Segundo 1-E commenced drilling in December 1995 and reached total
depth in mid-January 1996. The well encountered the Cimarrona formation, at a
measured depth of 5,718 feet. Due to the circulation problems encountered while
drilling, we stopped drilling after penetrating only 88 feet of the Cimarrona.
The well was then completed open hole in February 1996. Open hole means that the
well did not have casing, which is heavy steel pipe used to seal off fluids from
the hole or to keep the hole from caving in. During initial production testing
conducted in 1996, the El Segundo 1-E produced oil at an average rate of 2,282
BOPD. As of December 31, 2001, cumulative oil production from this well was
48,435 barrels of oil. This well is currently being used as a field pressure
observation well.

A third well, El Segundo 1-N, reached total measured depth of 6,820 feet in
November 1996. This well was intentionally deviated from the surface location of
El Segundo 1-E to a bottom hole location approximately 2,000 feet north. The
well encountered approximately 352 feet of oil saturated and highly fractured
Cimarrona reservoir rocks. During initial production testing conducted between
December 1996 and May 1997, the El Segundo 1-N produced oil at an average rate
of 2,867 BOPD. During a long-term production test conducted in the fourth
quarter of 1999, this well produced an average controlled rate of 1,750 BOPD. As
of December 31, 2000, cumulative oil production from this well was 180,333
barrels of oil.

A fourth well, El Segundo 1-S, was drilled and completed in September 1997
to a total measured depth of 6,920 feet. The bottom hole location of this well
is located approximately 2,000 feet south of the surface location of the El
Segundo 1-E well. During initial production testing, this well produced at an
average rate of 3,201 BOPD. During the 1999 long-term production test, this well
produced at an average controlled rate of 2,328 BOPD. Between August 2000, when
post-exploration phase production commenced,

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and December 31, 2000, this well produced oil at average controlled rate of
2,711 BOPD. Cumulative oil production as of December 31, 2000 from this well was
440,838 barrels of oil.

In October 1997, a fifth well, the Tres Pasos 1-E was drilled at a location
approximately 8,500 feet northwest of the El Segundo 1-E. The Tres Pasos 1-E was
the first well on the Rio Seco association contract. The Tres Pasos 1-E well was
completed at a measured depth of 6,150 feet. Analysis of reservoir pressure data
during production testing indicated pressure communication with all three El
Segundo 1 wells. We believe this pressure communication over a 8,500-feet
distance supports core studies showing an intensive degree of inter-connected
fractures. The pressure communication also supports core studies showing the
large calculated permeability within the area of the Cimarrona formation
investigated during production testing. During initial production testing
conducted in the fourth quarter of 1997, the Tres Pasos 1-E produced oil at an
average rate of 2,690 BOPD. It was further tested during the 1999 long-term
production test at an average rate of 2,721 BOPD. Between August 2000, when
post-exploration phase production commenced, and December 31, 2000, this well
produced oil at an average controlled rate of 1,933 BOPD. Cumulative oil
production as of December 31, 2000 from this well was 375,358 barrels of oil.

In November 1997, the sixth well, El Segundo 2-E was drilled to a measured
depth of 6,292 feet on the Dindal association contract. It was located
approximately 19,532 feet north of the surface location of the El Segundo 1-E
discovery well. Analysis of pressure data during production testing indicated
pressure communication with the El Segundo 1-S well, which has a bottom hole
location approximately 20,100 feet to the south of the El Segundo 2-E bottom
hole. These data further confirmed the presence of a pervasive fracture system
supporting the evidence for extensive permeability within the Cimarrona
formation over the area investigated during the production testing. During
initial production testing conducted in the fourth quarter of 1997 and the first
quarter of 1998, the El Segundo 2-E produced oil at an average controlled rate
of 2,730 BOPD. This well was not tested during the 1999 long-term production
test. Between August 2000, when post-exploration phase production commenced, and
December 31, 2000, this well produced oil at an average controlled rate of 742
BOPD. Cumulative oil production as of December 31, 2000 from this well was
47,219 barrels of oil.

In December 1997, the seventh well, Tres Pasos 2-E, was drilled to a
measured depth of 6,054 feet on the Rio Seco block approximately 29,600 feet
northwest of the surface location of El Segundo 1-E. The well encountered 290
feet of the Cimarrona formation reservoir. Due to an operational problem that
resulted from a failure to properly cement liner casing through the Cimarrona
formation, we drilled a new side-tracked well bore. The Tres Pasos 2-E
side-track reached a total measured depth of 5,880 feet with a bottom hole
location approximately 900 feet southeast of the surface location. In October
2000, we completed and tested the side-track well bore of the Tres Pasos 2-E,
which produced non-commercial quantities of oil and gas. We have temporarily
abandoned the well pending the evaluation of a hydraulic fracture treatment.

In November 1997, drilling commenced on the eighth well, El Segundo 3-E,
located approximately 14,800 feet south of the surface location of the El
Segundo 1-E well on the Dindal block. The drilling of El Segundo 3-E was
completed at a measured depth of 8,021 feet in February 1998. The well
encountered 292 feet of Cimarrona formation. Customary log analysis indicated
similar characteristics of lithology and fracturing similar to that observed in
previous wells; however, unlike the other wells, there were no oil shows, only
natural gas shows. This well was not cored. After the completion of drilling
operations on El Segundo 3-E, we experienced significant mechanical problems
while attempting to complete the well for production testing. We have
temporarily abandoned the El Segundo 3-E well.

The ninth well, El Segundo 6-E, is located on the Dindal block approximately
28,000 feet south of the surface location of the El Segundo 1-E well. In June
1998, the El Segundo 6-E well reached a total measured depth from the surface of
8,669 feet. Our preliminary analyses while drilling indicated highly fractured
core samples and over 300 feet of Cimarrona reservoir rocks with no apparent
indication of oil-water contact and shows of oil and gas. During production,
there was only a small show of oil and gas along with large quantities of water.
Attempts to eliminate water migrating from behind the pipe were unsuccessful.
During the second half of 2000, we redrilled the El Segundo 6-E well to a total
measured depth of 9,250 feet. During a 15-day production test, the well produced
oil and no water at an average rate of 320 barrels per day from a non-stimulated
open hole portion of the Cimarrona formation. The production was not limited by
the size of the pump used in the testing. However, sediments filling a
significant portion of the open-hole productive zone may have reduced
production. The Company will review the production and pressure data from the El
Segundo 6-E redrill to determine future plans for the well, which may include
cleaning out the Cimarrona portion of the well bore, running a slotted or
cemented production liner, and stimulating all or selected intervals of the
Cimarrona. Because the well is located approximately seven kilometers from the
Guaduas Oil Field's existing production and loading facilities, the Company
plans to delay future completion and production operations on the El Segundo 6-E
redrill until the Guaduas - La Dorada pipeline is closer to its projected
completion date of mid-2001. Cumulative oil production as of December 31, 2000
from this well was 4,937 barrels of oil.

In July 1998, we completed drilling operations on the tenth well, Tres Pasos
4-E. This well is located on the Rio Seco association contract area,
approximately 16,400 feet northwest from the surface location of the El Segundo
1-E discovery well. The well reached a total measured depth of approximately
6,300 feet. The Tres Pasos 4-E well encountered 303 feet of Cimarrona formation
with oil and gas shows. However, the well bore did not appear to intersect the
larger fracture system due to a rotation in reservoir fracture system
orientation at the well's bottom hole location. Consequently, the well may not
be commercially productive. We are still evaluating and

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analyzing the well, using bottom hole pressure recording to determine whether a
side-track lateral/horizontal well bore is warranted.

In September 1998, we drilled the eleventh well, Tres Pasos 3-E, located on
the Rio Seco block approximately 10,000 feet south of the Tres Pasos 1-E well.
The Tres Pasos 3-E well encountered 282 feet of Cimarrona with oil and gas
shows. Drilling was then extended to a total measured depth of 10,187 feet in
the deeper Villeta formation where shows of oil and gas were encountered. In
February 1999, we perforated the deeper Villeta formation, the secondary zone of
interest, which resulted in natural gas shows but not in commercial quantities
of oil and gas. The shallower Cimarrona formation objective has not yet been
tested. Perforating and testing of the Cimarrona formation is scheduled in 2001.

In December 1998, we completed drilling the twelfth well. This well, Tres
Pasos 1-WH, was our first horizontal/lateral well. It is approximately 6,500
feet west and 2,300 feet north of the El Segundo 1-E. It was drilled to a
measured depth of 7,180 feet on the Rio Seco block. The horizontal bore hole
penetrated 1,160 feet of the Cimarrona reservoir. Significant rates of oil flow
were encountered while drilling the reservoir and no indications of oil-water
were encountered. The well was production tested from January 7, 1999 until May
18, 1999 at an average rate of 1,530 BOPD. During the long-term production test
conducted in the fourth quarter of 1999, this well produced at an average rate
of 1,689 BOPD. As of December 31, 2000, cumulative oil production from this well
was 106,125 barrels of oil.

In December 1999, we drilled the thirteenth well, El Segundo 4-E, on the
Dindal block located approximately 8,200 feet southeast of the El Segundo 1-N
discovery well. The well reached a measured depth of 6,200 feet. The well was
production tested in February and March of 2000. According to preliminary
analysis, the well did not encounter the Cimarrona reservoir. The El Segundo 4-E
has been shut in for pressure build up after testing gas from the open hole at
rates of approximately 200 mcf/d. We will determine the future disposition of
the well based on further evaluation of this data.

TABLE OF GUADUAS OIL FIELD WELLS

The table below sets out cumulative and average production for the Guaduas
Oil Field wells as of December 31, 2000.

CUMULATIVE
OIL AVERAGE
PRODUCTION AS TEST
MEASURED OF PRODUCTION
YEAR ASSOCIATION DEPTH 12/31/00(1) RATE(2)
WELL NAME DRILLED CONTRACT (FEET) (BARRELS) (BARRELS/DAY) STATUS
----------------- --------- ----------- -------- ------------- ------------- --------------------------------

Escuela 1........ 1994 Dindal 7,802 -- -- Plugged and abandoned
El Segundo 1-E... 1995/1996 Dindal 5,718 48,435 2,282 Discovery well; Pressure
observation
El Segundo 1-N... 1996 Dindal 6,820 180,333 1,750 Oil and gas well
El Segundo 1-S... 1997 Dindal 6,920 440,838 2,328 Oil and gas well
Tres Pasos 1-E... 1997 Rio Seco 6,150 375,358 2,721 Oil and gas well
El Segundo 2-E... 1997 Dindal 6,292 47,219 742 Oil and gas well
Tres Pasos 2-E... 1997 Rio Seco 5,880 -- -- Temporarily abandoned
El Segundo 3-E... 1997 Dindal 8,021 -- -- Non-commercial test; may
side-track
El Segundo 6-E... 1998/2000 Dindal 9,250 4,937 320(3) Oil and gas well
Tres Pasos 4E.... 1998 Rio Seco 6,300 -- -- Non-commercial test; may
side-track
Tres Pasos 3E.... 1998 Rio Seco 10,187 -- -- Waiting on Cimarrona completion
Tres Pasos 1-WH.. 1998 Rio Seco 7,180 106,125 1,689 Oil and gas well
El Segundo 4-E... 1999 Dindal 6,200 -- -- Evaluating test results

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(1) Cumulative production as of December 31, 2000 was 1,203,245 barrels of
oil from the seven productive wells listed in the table.

(2) Average rate of production during the 1999 long-term production test,
unless the well was not produced at that time. If the well was not
tested during the 1999 long-term production test, the rate refers to
the average production rate during initial testing.

(3) During a 15-day production test, the El Segundo 6-E tested at an
average rate of 320 barrels per day.

GEOLOGY AND RESERVOIR CHARACTERISTICS OF THE GUADUAS OIL FIELD

The Guaduas Oil Field geological structure is a large anticlinal structure.
An anticlinal structure is a sub-surface, geological structure that rises to a
rounded peak. The primary oil reservoir is the Upper Cretacous Cimarrona
formation, which is located on the west flank of the Villeta anticline with an
average dip of 14 degrees at a depth of between approximately 6,000 and 8,000
vertical feet. The reservoir comprises both limestone and sandstone and is
under-pressured. The oil is characterized by low sulfur content of approximately
0.5%, low paraffin content, a medium gravity of between 18 degrees to 20 degrees
API, and a pour point of minus 34 degrees Fahrenheit.

The reservoir is generally intensely fractured and has indicated high
permeability in the wells that successfully produced oil and gas. Pressure test
analysis indicates the reservoir to be connected in most directions by large
fractures that allow hydrocarbons to flow

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readily through the reservoir. We believe that these highly permeable fractures,
in conjunction with the angle of the formation dip, will allow the oil to be
produced by a combination of efficient oil recovery mechanisms, including
gravity drainage, gravity segregation and pressure maintenance.

PRODUCTION FACILITIES, GATHERING AND PIPELINE SYSTEMS FOR THE GUADUAS OIL FIELD

In January 2000, we completed the construction of the production facility
that has been used since August 2000 for the production of between 4,000 - 6,000
BOPD. We currently have four 5,000-barrel storage tanks at this production
facility, providing storage capacity of 20,000 barrels.

In July 2000 we received the required environmental permits for the Guaduas
- - La Dorada Pipeline and the related production facilities. The approximate
36-mile Guaduas - La Dorada Pipeline will connect the Guaduas Oil Field to
international oil markets via Colombia's existing pipeline infrastructure.
Operations to construct this pipeline commenced in October 2000. We have
completed the purchase of rights-of-way for the pipeline route, taken delivery
of the 10-inch pipe for the pipeline, nearly completed the clearing of the
pipeline route, and successfully completed underground river crossing, the most
difficult part of the construction. As of the filing date of this report, the
Guaduas - La Dorada Pipeline remained on schedule for a mid-year 2001
completion.

The Guaduas - La Dorada Pipeline will transport Guaduas Oil Field production
to La Dorada, a small town north of the field, where it will intersect with the
Oleoducto Alto Magdalena (OAM) pipeline, a regional pipeline that transports oil
production from the Upper and Middle Magdalena river valley to the oil refining
and terminal city of Vasconia. In Vasconia, the OAM pipeline connects with the
Oleoducto de Colombia (ODC) and the Oleoducto Central S.A. (OCENSA) pipelines,
both of which transport oil to the export terminal facilities at the Caribbean
port of Covenas. In early 2001, we signed an agreement to transport our share of
the Guaduas Oil Field crude oil production through the OAM and ODC pipelines.

DEEP DINDAL ASSOCIATION CONTRACT

In February 2001, we acquired the Deep Dindal association contract, which is
also known as an "on top" contract because it originated from the Dindal
association contract. This association contract has the same surface area as the
Dindal association contract (approximately 65,000 acres), but it only applies to
the areas below the base of the Guaduas Oil Field. This area contains the
subthrust Dindal prospect, which we plan to test with an exploration well in
2001. We have a 100% interest in this association contract subject to an
obligation to assign some of this interest to Sipetrol and Cimarrona, our
partners in the Guaduas Oil Field, pursuant to an Exploration agreement we
signed with them in January 2001. Following the drilling of a exploration well
to test the subthrust Dindal prospect, we will have to assign either a 25.85%
collective interest to Sipetrol and Cimarrona, or a 9.4% interest percent to
Cimarrona and provide Sipetrol with a 4.86% overriding royalty interest that is
reducible by Colombian government participation in the project. Additional
information on the exploration agreement, which is a part of a larger agreement
with our partners, is available in a Form 8-K filed with the U.S. Securities and
Exchange Commission on January 31, 2001.

The terms of the Deep Dindal association contract are similar to the Rio
Seco association contract terms insofar as the Associates are responsible for
100% of the exploration costs, Ecopetrol will have a right to participate in the
development and production of a discovery, and Ecopetrol's interest will
increase as the ratio of accumulated income attributable to the Associates (less
any expenses reimbursed by Ecopetrol) increases from a one-to-one ratio to a
two-to-one ratio. However, Ecopetrol's initial interest will be 30%, as compared
to 50% under the Rio Seco and Dindal association contracts, and will increase
only to 65%, as compared to 75% under the Rio Seco association contract and 70%
under the Dindal association contract. Another benefit of the Deep Dindal
association contract is that it is a full 28-year contract, including a 25-year
production period, as compared to a 22-year production period under the Dindal
and Rio Seco association contracts.

The Deep Dindal association contract requires that we drill an exploration
well during each of its two eighteen month exploration stages, the first of
which commences on April 24, 2001, the effective date of the association
contract, and the second of which commences at the end of the first. We plan to
drill an exploration well at an estimated cost of $15 million in 2001 to satisfy
the first eighteen-month requirement. Our plans are contingent upon 1) our
ability to secure the financing for the 100% of the costs of drilling and
testing this well, and 2) receiving the required environmental permit.

In 1999, the Colombian government enacted a new royalty regime for oil and
gas fields discovered after the date of enactment. Under the new regime, the
royalty on oil and gas production of new discoveries will be a variable royalty
that begins at 5% and rises to 20% as cumulative hydrocarbon production
increases. Under the old royalty regime, oil and gas production was subject to a
fixed 20% royalty. Because the Guaduas Oil Field was discovered before the
enactment of the new royalty regime, production from this field will be subject
to the fixed 20% royalty. If a discovery is made in the area covered by the Deep
Dindal association contract, it will be subject to the new royalty regime.

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CRISTALES ASSOCIATION CONTRACT

In February 2001, we acquired the Cristales association contract, covering
an area of approximately 200,000 gross contiguous acres located immediately to
the east of the Dindal and Deep Dindal association contract areas. We have a
100% interest in this association contract. The fiscal terms of the Cristales
association contract are identical to the Deep Dindal terms, with one exception:
the Cristales association contract has a 6-year exploration period and a 22-year
production period, as compared to a 3-year exploration period and a 25-year
exploration period under the Deep Dindal association contract. Our first year
obligation under this contract is to conduct remote sensing work and other
geological and geochemical studies at an expected cost of $350,000. Colombia's
new royalty regime will be applied to any discovery made with the Cristales
association contract area.

ROSABLANCA ASSOCIATION CONTRACT

Effective February 28, 1998, we acquired a 75% interest in the adjoining
Rosablanca and Montecristo association contract areas. In late 2000, we reached
an agreement with Ecopetrol to drill one well on the Rosablanca association
contract area and relinquish the Montecristo association contract to satisfy
various second and third year work obligations under these contracts.
Additionally, in accordance with the contract terms, we recently reduced the
size of the Rosablanca contract area by approximately 74,000 acres. The
Rosablanca contract now covers approximately 242,500 gross contiguous acres in
the northern Middle Magdalena Basin. Under the terms of the recently signed
agreement with Ecopetrol, the well on the Rosablanca contract was supposed to be
started by February 28, 2001. However, we have not received the required
environmental permit from the Colombian Ministry of Environment. Consequently,
Ecopetrol granted us a six-month extension to drill this well. This well, to be
called the Santa Fe - 1, will be drilled to an estimated total depth of 3400
feet at an estimated gross cost of $1.0 million.

The terms of the Rosablanca association contract are similar to the Rio Seco
association contract, but with two major beneficial changes. First, after a
declaration of commerciality, Ecopetrol's interest in production and costs would
be on an individual-field basis rather than being applicable to the entire
contract. Second, the Rosablanca association contract provides for an additional
term of four years in the event a gas field is discovered. Colombia's new
royalty regime will be applied to any discovery made within the Rosablanca
association contract area.

On November 8, 2000, we notified Potomac Energy Corporation, a 25% working
interest partner in the Rosablanca association contract, that it was in default
of approximately $0.4 million of its share of costs under the joint operating
agreement. Potomac had to remedy the default by January 8, 2001 to avoid
forfeiting its interest in the contract area. Potomac did not remedy the
default, and as a result, we now have a 100% interest in the association
contract.

TAPIR ASSOCIATION CONTRACT

In April 1996, we acquired an 11.875% initial working interest in the Tapir
association contract, which covers 116,795 acres in Colombia's Central Llanos
basin and is located 40 miles east of the Cusiana Field. The Tapir association
contract was effective on February 6, 1995 on terms substantially similar to the
Rio Seco association contract. Mohave Colombia Corporation (Mohave) is the
operator and 37.5% working interest owner of the Tapir association contract. The
other two initial working interest owners are Doreal Energy Corporation with
12.5% and Solana Petroleum Exploration Colombia (Solana) with 38.125%

In 1998, we participated in the Mateguafa-1 well, which produced oil at a
rate of 777 BOPD during testing. In 1999, we participated in the Caporal-1 well
to test a different prospect within the Tapir contract area. The Caporal-1 well
was a dry hole. During the first half of 2000, we participated in the
Mateguafa-2A well, located 1.8 kilometers south of the Mateguafa-1 well. This
well has not been tested, but is scheduled for completion and testing operations
in 2001 along with additional production testing of the Mateguafa-1 well.

In August 2000, we signed a purchase and sale agreement with Solana to sell
our 11.875% interest in the Tapir association contract for 3,000,000 common
shares of Solana's parent corporation, Solana Petroleum Corporation. Seven Seas
and Solana have subsequently agreed to terminate this purchase and sale
agreement. Additionally, Solana is in default for failure to pay its
participating share of Joint Account expenses, and has agreed to relinquish its
interest in the Tapir association contract. We have agreed to be assigned our
proportionate share of the interest in the Tapir association contract that
Solana will relinquish. Upon receipt of that assignment, our interest in the
Tapir association contract will increase to approximately 19.19%

In January 2001, Mohave will begin the sixth year work program. The proposed
program includes the construction of an all-weather road, production testing the
Mateguafa 1 and 2 wells, and drilling an exploratory well. With our 19.19%
interest in the Tapir association contract, our share of costs of the 2001 work
program is estimated to be $2.1 million. We will, however, continue to look for
a potential purchaser for our interest.

OIL AND GAS RESERVES

The following table sets forth our estimated net proved oil and gas
reserves, the estimated future net revenues before income taxes, the present
value of estimated future net revenues before income taxes related to proved
reserves and the standardized measure of

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discounted future net cash flows related to proved reserves, in each case as of
December 31, 2000 and 1999. All information relating to estimated net proved oil
and gas reserves and the estimated future net revenues and cash flows
attributable thereto is based upon a report from Ryder Scott Company Petroleum
Consultants. All calculations of estimated net proved reserves have been made in
accordance with the rules and regulations of the United States Securities and
Exchange Commission.

AS OF AS OF
DECEMBER 31, DECEMBER 31,
2000(1) 1999
------------ ------------

Total net proved reserves:
Oil (MBbls) ................................................... 47,992 34,880
Gas (MMcf) .................................................... -- --
Total (MBOE) .................................................. 47,992 34,880
Net proved developed reserves:
Oil (MBbls) ................................................... 15,853 11,001
Gas (MMcf) .................................................... -- --
Total (MBOE) .................................................. 15,853 11,001
Estimated future net revenues before income taxes
(in thousands)(2) ............................................. $ 670,068 $ 605,603
Present value of estimated future net revenues before income
taxes
(in thousands)(2) ............................................. $ 394,054 $ 311,374
Standardized measure of discounted future net cash flows
(in thousands)(2)(3) .......................................... $ 289,345 $ 230,967

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(1) The increase in the Company's net reserves is principally due to the May
2000 decision by Ecopetrol, Colombia's national oil company, not to
participate in the development of the Guaduas Oil Field and to permit Seven
Seas and its partners to proceed on a sole-risk basis.

(2) The present value of estimated future net revenues was prepared using
constant prices as of December 31, 2000 and 1999, discounted at 10% per
annum on a pre-tax basis. The net price for 2000 was calculated using the
December 31, 2000 price of $26.80 per barrel, less $8.64 per barrel for
gravity adjustment and transportation and marketing costs, yielding a net
price of $18.16 per barrel. The net price for 1999 was calculated using the
December 31, 1999 price of $25.60 per barrel, less $4.50 per barrel for
gravity adjustment and transportation and marketing costs, yielding a net
price of $21.10 per barrel.

(3) The standardized measure of discounted future net cash flows represents the
present value of estimated future net revenues from proved reserves after
income tax, discounted at 10% per annum.

Reservoir engineering is a subjective process that involves estimating
underground accumulations of gas and oil that cannot be measured in an exact
way. The accuracy of any reserve estimate depends on the quality of available
data, and on engineering and geological interpretation and judgment. As a
result, estimates made by different engineers often vary. In addition, results
of drilling, testing and production subsequent to the date of an estimate may
justify revision of the estimates. These revisions may be material. Accordingly,
reserve estimates are generally different from the quantities of gas and oil
that are ultimately recovered.

Approximately 67% of our total estimated proved reserves at December 31,
2000 were undeveloped. Recovery of these reserves will require significant
spending and successful drilling and completion operations. Although estimates
of our reserves and related costs have been prepared in accordance with industry
standards, we cannot be certain that the estimated costs are accurate, that
development will occur as scheduled or that the results will be as estimated.

PRODUCTIVE WELLS

The following table sets forth the gross, or total, number of productive oil
and gas wells in which we have an interest as of December 31, 2000 and also sets
forth the net number as of the same date. The net number of productive wells is
determined by multiplying the number of gross wells by our working interests in
those wells.

WELLS(1)
---------------------------------
OIL GAS
--------------- ---------------
GROSS NET(2) GROSS NET(2)
------ ------ ------ ------

Colombia ............ 9 4.4 0 0.0
------ ------
Total .......... 9 4.4 0 0.0

- ----------

(1) One or more completions in the same well bore are counted as one well.

(2) Net interests are based on our respective working interests in the
association contracts that cover the areas in which these wells were
drilled, and are before Ecopetrol's participation.

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ACREAGE

The following table sets forth estimates of our gross and net developed and
undeveloped acreage for which oil and gas leases or association contracts were
held as of December 31, 2000. The gross acres number reflects the total number
of acres in which we have an interest, without regard to the size of that
interest. Net acres are determined in the same way that net wells are
determined, by multiplying the gross acres by our interest in those acres.
Undeveloped acreage means acreage on which wells have not been drilled or
completed to a point that would permit the production of commercial quantities
of oil and gas regardless of whether the acreage contains proved reserves.

DEVELOPED UNDEVELOPED
--------------------------- ---------------------------
GROSS ACRES NET ACRES(1) GROSS ACRES NET ACRES(1)
------------ ------------ ------------ ------------

Colombia .......... 12,821 7,398 719,474 524,206
Total ........ 12,821 7,398 719,474 524,206

- ----------

(1) Net acres are based on our respective working interests in the association
contracts that cover these areas, and are before Ecopetrol's participation.

DRILLING ACTIVITY

The following table sets forth the number of wells drilled by us from
inception through December 31, 2000:

EXPLORATORY DEVELOPMENT
--------------------------------- ---------------------------------
PRODUCTIVE DRY PRODUCTIVE DRY
--------------- --------------- --------------- ---------------
GROSS NET(1) GROSS NET(1) GROSS NET(1) GROSS NET(1)
------ ------ ------ ------ ------ ------ ------ ------

Year ended December 31, 2000:
Colombia ........................ 2 0.8 0 0.0 0 0.0 0 0.0
Year ended December 31, 1999:
Colombia ........................ 0 0.0 2 0.7 0 0.0 0 0.0
Year ended December 31, 1998:
Colombia ........................ 2 0.8 5 2.9 0 0.0 0 0.0
Year ended December 31, 1997:
Colombia ........................ 3 1.7 0 0.0 0 0.0 0 0.0
Year ended December 31, 1996:
Colombia ........................ 2 1.2 0 0.0 0 0.0 0 0.0
Argentina ....................... 0 0.0 1 0.3 0 0.0 0 0.0
------ ------ ------ ------ ------ ------ ------ ------
2 1.2 1 0.3 0 0.0 0 0.0
Year ended December 31, 1995:
Australia ....................... 0 0.0 1 0.1 0 0.0 0 0.0

- ----------

(1) Our net interests in wells located in Colombia are before Ecopetrol's
participation.

OTHER INFORMATION

We have included additional information regarding our oil and gas operations
in the notes to our 2000 consolidated financial statements. This information
addresses:

o our capitalized costs related to our oil and gas activities incurred in
2000, 1999 and 1998;

o our development, property acquisition and exploration costs incurred in
2000, 1999 and 1998;

o our proved reserves in 2000, 1999 and 1998;

o the standardized measure of discounted future net cash flows attributable
to our proved oil reserves for 2000, 1999 and 1998; and

o the principal sources of changes in our standardized measure of discounted
future net cash flows in 2000, 1999 and 1998.

ITEM 3. LEGAL PROCEEDINGS

HEIRS OF NICOLAS BELTRAN FRANCO

Two of our subsidiaries, Petrolinson, S.A. and GHK Colombia, along with the
former owner of Petrolinson, S.A., Norman Rowlinson and the heirs of Howard
Thomas Corrigan, are defendants in a lawsuit that was filed in Santa Fe de
Bogota, Colombia in 1998. The plaintiffs are the heirs of Nicolas Beltran
Franco. The plaintiffs have two claims. First, they claim that a de facto
company

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existed between Nicolas Beltran Franco and the defendants concerning the Dindal
and Rio Seco association contract areas. Second, they claim that before the
Dindal and Rio Seco association contracts were executed, the de facto company
conducted exploration works in the Dindal and Rio Seco association contract
areas. The plaintiffs claim they have the right to participate in income earned
from the Dindal and Rio Seco association contract areas. None of the plaintiffs
are party to the association contracts. However, they are seeking 50% of the
income generated by the de facto company they claim existed. It is not clear
what percentage of the Dindal and Rio Seco association contract areas are
covered by the plaintiffs' claims. Our Colombian counsel, Raisbeck, Lara,
Rodriguez and Rueda, members of the law firm of Baker and McKenzie, believe that
if this claim is litigated the chances of the plaintiffs succeeding are remote.

SURFACE LOCATION

A lawsuit was filed by the landowner of the El Segundo 1 surface location to
cancel our surface lease. We responded to this claim on November 4, 1999, and
have vigorously defended this claim. Examinations regarding the claim were held
in September 2000, and the probatory stage of the matter was closed on March 21,
2001. Our Colombian legal counsel advised us that, on the basis of the claims
asserted, it is unlikely that we will lose the lawsuit.

NOTEHOLDER CLAIM

A claim has been brought against Seven Seas by one of the noteholders in
connection with the Special Notes issued on August 7, 1997. The claim, which is
against Seven Seas and Yorkton Securities Inc., alleges that the noteholder was
not initially advised of the right of Seven Seas to convert the debentures into
units of common shares and warrants. The claim also alleges that there were
errors in the methodology of effecting conversion pursuant to the indenture
between Seven Seas and Montreal Trust Company of Canada dated August 7, 1997
such that the conversion was not effective. The plaintiff in the claim is
seeking damages against Seven Seas in the amount of $340,000 for negligent
misrepresentation and breach of contract or alternatively, for an order
directing Seven Seas to exchange the units currently held by the plaintiff into
a note in the amount of $340,000 payable on July 24, 2002 with interest payable
thereon at a rate of 6% per annum or directing Seven Seas to reimburse the
plaintiff in the amount of $340,000 for the purchase price of the Special Notes.
Seven Seas believes it has meritorious defenses and intends to take appropriate
steps to defend the action vigorously.

FORMER MANAGEMENT

Seven Seas and two of its officers and directors, Robert A. Hefner, III and
Larry Ray, and one of its former directors, Breene M. Kerr, have been sued by
four former Seven Seas officers and directors in DeCort, et al. v. Seven Seas
Petroleum Inc., et al., Cause No. 2000-50498, District Court of Harris County,
Texas, 133rd Judicial District. Plaintiffs allege that Seven Seas failed to
obtain extensions of time in which the plaintiffs could exercise certain stock
options granted to them, and that all defendants induced them to enter into
separation agreements with Seven Seas that they would have not entered into but
for Seven Seas' agreement to obtain an extension of time for plaintiffs to
exercise their stock options. The plaintiffs filed the case October 2, 2000,
seeking damages in excess of $13 million. The Company has responded, denying
plaintiffs' allegations and the case is in the early stages of discovery.
Mediation is currently scheduled for late April and a preliminary trial date
has been set for June. Seven Seas intends to vigorously defend the case.

FORMER EMPLOYEE

A lawsuit has been filed against GHK Company Colombia in the Bogota labor
court by a former employee who claims that he incurred $1.6 million in expenses
in connection with a criminal action filed against him in Guaduas. Our Colombian
legal counsel has advised us that it is unlikely that we will lose the lawsuit
due to the fact that, upon his departure from service, the plaintiff
acknowledged that GHK had paid in full all monies owed.

OTHER

Other than the cases mentioned above, and the penalty imposed by the
Ministry of Environment described in "Business -- Regulation -- Environmental
penalties" above, we are not a party to any material proceedings and our
property is not the subject of a material proceeding.

ITEM 4. SUBMISSION OF MATTERS TO A VOTE OF SECURITY HOLDERS

None

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PART II

ITEM 5. MARKET FOR REGISTRANT'S COMMON EQUITY AND RELATED STOCKHOLDER MATTERS

Our common shares have been listed on the American Stock Exchange under the
symbol "SEV" since January 9, 1998. From February 10, 1997 until March 9, 2001,
our shares were also listed on The Toronto Stock Exchange in Toronto, Ontario,
Canada under the symbol "SVS.U." Effective at the close of business on March 9,
2001, we delisted our shares from The Toronto Stock Exchangein connection with
our continuance from the Yukon Territory to the Cayman Islands.

The following tables summarize the high and low sales prices for each full
quarterly period within the two most recent fiscal years. The prices listed
below are stated in U.S. dollars, which is the currency in which they were
quoted.

THE TORONTO STOCK EXCHANGE

HIGH LOW
-------- --------

1999
First Quarter ................ $ 9.10 $ 3.60
Second Quarter ............... 5.05 2.65
Third Quarter ................ 4.05 2.36
Fourth Quarter ............... 3.15 1.51
2000
First Quarter ................ $ 3.00 $ 1.50
Second Quarter ............... 2.25 0.80
Third Quarter ................ 3.70 0.80
Fourth Quarter ............... 3.52 1.00

The following table summarizes the high and low sales prices as reported on
the American Stock Exchange for the periods listed below.

AMERICAN STOCK EXCHANGE

HIGH LOW
-------- --------

1999
First Quarter ................ $ 9.25 $ 3.56
Second Quarter ............... 5.13 2.50
Third Quarter ................ 4.19 2.50
Fourth Quarter ............... 3.19 1.50
2000
First Quarter ................ $ 3.19 1.69
Second Quarter ............... 2.06 0.94
Third Quarter ................ 3.88 1.00
Fourth Quarter ............... 3.88 0.81

As of March 28, 2001, there were approximately 679 shareholders of record.
We have never declared or paid cash dividends on our common shares. We expect to
retain all earnings in the foreseeable future for the development of our
business.

ITEM 6. SELECTED FINANCIAL DATA

The following table sets forth certain historical consolidated financial
data for Seven Seas as of and for each of the periods indicated. The following
data should be read in conjunction with "Management's Discussion and Analysis of
Financial Condition and Results of Operation" and our consolidated financial
statements and accompanying notes included elsewhere in this document.

YEAR ENDED DECEMBER 31,
------------------------------------------------------------------
2000 1999 1998 1997 1996
---------- ---------- ---------- ---------- ----------
(IN THOUSANDS, EXCEPT PER SHARE AMOUNTS)

INCOME STATEMENT DATA:
Revenue ................................... $ 6,434 $ 5,313 $ 3,797 $ 1,567 $ 575
Net loss .................................. (5,907) (6,789) (90,199) (7,928) (2,195)
Net loss per common share ................. (0.16) (0.18) (2.49) (0.24) (0.17)
Weighted average shares
outstanding ............................ 37,836 37,862 36,204 32,505 12,972
BALANCE SHEET DATA (END OF
PERIOD):
Cash and cash equivalents ................. $ 12,128 $ 22,447 $ 38,147 $ 18,067 $ 10,620
Total assets .............................. 254,076 261,082 279,900 291,914 235,501
Current liabilities ....................... 8,704 9,714 12,357 8,205 2,806
Long-term debt ............................ 110,000 110,000 110,000 25,000 --
Minority interest ......................... -- -- 9,713 4,087 1,060
Stockholders' equity ...................... 110,669 116,574 123,098 184,163 167,667

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In June 1999, we restructured our interest in Colombia resulting in the
elimination of a minority interest owner in one of our subsidiaries. There was
no impact on our net ownership interest in the Guaduas Oil Field. See footnote
14 to the financial statements for a further discussion.

ITEM 7. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS
OF OPERATION

INTRODUCTION

The following discussion is intended to assist in understanding our
financial position and results of operations for each year in the three-year
period ended December 31, 2000.

OVERVIEW

Our principal asset is a 57.7% interest, before participation by Ecopetrol,
in the Dindal and Rio Seco association contracts, which cover the area in which
the Guaduas Oil Field is located. As of December 31, 2000, Ryder Scott Company
Petroleum Consultants estimated total proved recoverable reserves for the
Guaduas Oil Field of 155.9 million barrels of oil, of which 47.9 million barrels
of oil were attributable to our interest.

Our current plans for the year 2001 are set forth under "Business -- Our
Current Strategy." Whether we can achieve our objectives on schedule depends on
a number of factors, many of which are not within our control. Factors include
securing financing to fund our share of costs for our 2001 development and
exploration strategy, timely environmental permitting, timely payments by the
association contract partners of their share of these costs and the market price
of oil field equipment and services. We will seek additional sources of
financing through project financing, industry joint ventures or arrangements
with industry service companies, commercial bank borrowings and traditional debt
and equity financing.

In our 1999 Form 10-K and subsequent U.S Securities and Exchange Commission
filings, we outlined three scenarios for moving forward with the development of
the Guaduas Oil Field. Scenario 1 assumed Ecopetrol participated in the
development of the Guaduas Oil Field. Scenario 2 assumed Ecopetrol did not
participate in the development of the field, but authorized Seven Seas and our
partners to proceed with development on a sole-risk basis. Sole-risk means that
Seven Seas and our partners pay 100% of development costs and retain all
revenues from production after the 20% Colombian royalty deduction. Ecopetrol
has the right to start participating in development at any time subject to Seven
Seas and partners' right to recover 200% of the development costs spent since
Ecopetrol's decision not to participate plus certain exploration costs. Scenario
2 also assumed that together with our partners we would proceed to develop the
field as proposed to Ecopetrol (i.e. construct a pipeline and drill development
wells for production of 20,000 BOPD to 30,000 BOPD). Like Scenario 2, Scenario 3
assumed that Ecopetrol would elect not to participate, but assumed that we would
modify our development program as proposed to Ecopetrol by postponing the
construction of the pipeline and development drilling.

2000 IN REVIEW

During the first quarter of 2000, we fulfilled our obligations under a
September 23, 1999 Memorandum of Understanding agreement with Ecopetrol that
eventually led to Ecopetrol's decision on whether to participate in the
development of the Guaduas Oil Field. Specifically, we completed the long-term
production test of the Guaduas Oil Field, producing close to 350,000 barrels of
oil, conducted a pressure-build up test and completed and tested the El Segundo
4-E well.

We continued our cost reduction program and reorganization of our Bogota
office, reducing the number of positions by approximately 42 at an annualized
savings of approximately $0.8 million. This cost reduction program, which
commenced in 1999, contributed to a $0.4 million decrease in our general and
administrative costs between 2000 and 1999, and a decrease of over $2.5 million
between 2000 and 1998. Our 2000 general and administrative costs included over
$1.3 million in non-reoccurring expenses associated with severance costs and our
continuance to the Cayman Islands.

Also during the first quarter of 2000, we hired J. Anthony Stuart, a 22-year
employee of British Petroleum, as our drilling manager in our Bogota office. Mr.
Stuart had spent the previous nine years working for BP in Colombia on the
development of the

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Cusiana-Cupiagua field, Colombia's largest known oil field. At the time of his
retirement from BP, Mr. Stuart was serving as Drilling Operations Manager. In
early 2001, we made Mr. Stuart Vice President of Operations of GHK Company
Colombia, our subsidiary in Colombia and the operator of the Guaduas Oil Field.
Mr. Stuart will oversee the drilling of the subthrust exploration well provided
it is drilled this year. Concurrent with Mr. Stuart's promotion, we also named
Claudia M. Vaca Vice President of Legal, Finance and Administration of GHK
Company Colombia. Prior to this position, Ms. Vaca, who is a graduate of the
Harvard Law School, was serving as GHK Company Colombia's General Counsel.

In July and August of 2000, after Ecopetrol decided not to participate in
the development of the Guaduas Oil Field and we decided to proceed sole-risk,
the Colombian Ministry of Environment and Ministry of Mines and Energy granted
all the permits and licenses required to develop and produce the Guaduas Oil
Field.

After we received the requisite Colombian governmental approvals and
licenses, we commenced post-exploration phase production of the Guaduas Oil
Field on August 9, 2000. With the exception of pre-scheduled field shut-in
periods or road closures, we produced and trucked between 4,000 BOPD and 6,000
BOPD for the remainder of the year, resulting in gross total production of over
400,000 barrels of oil, 189,988 of which were net to our interest.

In October 2000, we commenced operations for the construction of the
pipeline, ordering long-lead items such as pipe and pumps, and we began to
purchase rights-of-way.

During the fourth quarter of 2000, we re-drilled, completed and tested the
El Segundo 6-E well. During a fifteen day production test, the El Segundo 6-E
produced at an average rate of 320 BOPD, establishing production seven
kilometers south of the southern most productive well in the Guaduas Oil Field.

In November 2000, R. Randolph Devening was appointed to our Board of
Directors. Mr. Devening currently serves as Chief Executive Officer of
Foodbrands America, Inc., a leading U.S. producer, marketer and distributor of
frozen and refrigerated products. Mr. Devening joined Foodbrands America as
Chairman, President and CEO in 1994 when it was a public company listed on the
New York Stock Exchange and prior to it becoming a subsidiary of IBP, inc.
Before joining Foodbrands America, Mr. Devening held various senior level
positions, including Vice Chairman of the Board of Fleming Companies, Inc. Mr.
Devening is a graduate of Stanford University and holds a Masters in Business
Administration in Finance and Marketing from Harvard Business School. He
currently serves as director of Hancock Fabrics, Inc., Keystone Automotive
Operations, Inc., and Love's Country Stores, Inc.

In December 2000, we secured a $10 million loan from Stillwater National
Bank to be used primarily for the construction of the 36-mile Guaduas - La
Dorada pipeline.

Throughout the second half of the year, we were in negotiations with our
Guaduas Oil Field partners regarding their participation in the pipeline and the
subthrust Dindal prospect. These negotiations were completed in late-January
2001. Key aspects of the global partner agreement that we signed in January 2001
are as follows:

o Sipetrol and Cimarrona elected to participate in the construction of the
Guaduas - La Dorada pipeline.

o Sipetrol and Cimarrona agreed to provide Seven Seas with the opportunity
to earn certain of their interests in the subthrust Dindal prospect by
drilling a subthrust exploration well and paying Sipetrol and
Cimarrona's share of the costs of drilling and testing the well.

Additional information on our global partner agreement is available in a Form
8-K filed with the U.S. Securities and Exchange Commission on January 31, 2001.

In late 2000, we reached an agreement with Ecopetrol to drill an exploration
well on the Rosablanca association contract area and relinquish the Montecristo
association contract to satisfy various second and third year obligations under
these contracts.

One of the matters that culminated in early 2001, but which we worked on in
2000, was securing the Deep Dindal and Cristales association contracts. The Deep
Dindal association contract, which is generically referred to as an "on top"
contract because it originated from the Dindal association contract, covers the
subthrust Dindal prospect located below the Guaduas Oil Field. The Deep Dindal
contract provides better economic terms than the original Dindal association
contract. The Cristales association contract covers approximately 300,000 acres
immediately to the east of the Guaduas Oil Field and the subthrust Dindal
prospect.

Another matter that culminated in early 2001, but which we worked on in
2000, was continuing the Company to the Cayman Islands from the Yukon Territory,
Canada. The principal reason for the change of domicile was to lower our future
worldwide effective corporate tax rate. Other considerations were that most of
our shareholders are not Canadian and all of our oil and gas revenues are from
non-Canadian operations. On February 28, 2001 we received shareholder approval
for the continuation, and effective March 1, 2001 we continued as a Cayman
Island company.

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During the fourth quarter of 2000, we commenced a search for a chief
financial officer. In March 2001, we announced that Ronald A. Lefaive was
joining our Company as Vice President of Finance and Chief Financial Officer.
Mr. Lefaive has 25 years of finance and accounting experience in the domestic
and international oil and gas industry, including positions with Halliburton
Company, Chesapeake Energy Corporation, Phibro Energy Inc. and Shell Oil
Company. Additionally, he has an extensive background in information technology.
Mr. Lefaive is a certified public accountant and holds a Bachelor's of Business
Administration degree in accounting from the University of Houston.

In summary, in 2000, we took several important steps toward developing the
Guaduas Oil Field and securing a sustained source of cash flow. We also
positioned ourselves to test the upside potential of the subthrust Dindal
prospect in the near future under favorable terms with our partners and
Ecopetrol.

OUR CURRENT STRATEGY

Our strategy for 2001 and 2002 includes the continued development of the
Guaduas Oil Field and new exploration. A summary of our strategy follows:

Development

Pipeline and Production Facilities - We expect to complete the 36-mile La Dorada
- - Guaduas pipeline that will connect the Guaduas Oil Field to international oil
markets via Colombia's existing pipeline infrastructure by mid 2001. The
pipeline will have an initial capacity of approximately 25,000 BOPD, but can be
increased to 40,000 BOPD with additional investment. Since we broke ground in
January 2001, we have made the following progress:

o Completed the purchase of rights-of-way for the pipeline route

o Taken delivery of the 10-inch pipe for the pipeline

o Nearly completed the clearing of the pipeline route

o Successfully completed underground river crossing, the most difficult
part of the construction

o Secured access to existing pipelines that will transport Guaduas Oil
Field production from La Dorada, the end point of the pipeline we are
constructing, to the Caribbean port of Covenas

We completed construction of a production facility for the production of 4,000
BOPD to 6,000 BOPD in January 2000. We now have four 5,000-barrel storage tanks
on location, and we expect to complete the production facility for pipeline
production by mid 2001.

The gross costs of constructing the pipeline and production facilities are
approximately $24 million, our share of which is approximately $13.8 million.

Development Wells - We recently agreed with our Guaduas Oil Field partners to a
two-year development well drilling schedule that provides for the drilling of
nine development wells and one injector well for field pressure maintenance over
the course of 2001 and 2002. We believe these wells will increase pipeline
production of the Guaduas Oil Field from its initial rate of 8,000 BOPD - 10,000
BOPD to approximately 25,000 BOPD; however, actual production will depend on the
results of the development wells. The gross costs of this development well
drilling program is estimated to be $44 million, our share of which is
approximately $25 million. In 2001, four development wells and one injector well
are scheduled at a gross cost of $22 million, our share of which is
approximately $13 million. Implementing this development drilling program will
depend on our ability to finance our share of the costs.

In summary, our 2001--2002 development strategy includes completing the
Guaduas - La Dorada pipeline and production facilities for pipeline production
and drilling nine development wells and one injector well at a gross cost of $68
million, our share of which is approximately $40 million. In 2001, we expect to
complete the pipeline and production facilities and drill four of the nine
developments wells and the one injector well. The gross cost of 2001 development
operations, including the pipeline and production facilities is expected to be
approximately $46 million, our share of which is approximately $27 million.

Exploration

Subthrust Dindal Prospect - In 2001, we plan to drill an exploration well to
test the high potential subthrust Dindal prospect, located below the Guaduas Oil
Field. As of February 2001, this prospect is covered by the Deep Dindal
association contract that originated from the Dindal association contract. This
new contract provides more favorable fiscal terms than the original Dindal
association contract. Under the Deep Dindal association contract, our working
interest after Ecopetrol elects to participate in the development of an oil and
gas discovery starts at 70%, as compared to 50% under the Dindal contract.
Additionally, as oil production increases, our working interest will gradually
decrease to a minimum of 35%, as compared to 30% under the Dindal contract. In
January 2001, we signed a global agreement with our Guaduas Oil Field partners
that included a farm out of certain of their interests in the Deep Dindal
association contract. As a result of an exploration agreement with our Guaduas
Oil Field partners, we now have a 100% interest in the Deep Dindal association
contract, subject to an obligation to assign between approximately 14% and 26%
to our partners after the first well has been drilled and tested.

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In last year's Form 10-K, we estimated the gross costs of drilling and
completing this well would be approximately $18 million. This estimate was based
on the assumption that we would have to drill the well outside of an area that
the Municipality of Guaduas had declared a forest reserve prohibiting oil and
gas operations. The Municipality has subsequently revoked that forest reserve
and adopted a previously created national forest reserve as the only existing
reserve. The existing forest reserve does not prohibit oil and gas activities,
and in fact, the Escuela 1, the first well drilled on the Dindal association
contract by our subsidiary GHK Company Colombia, was drilled from a surface
location within the existing forest reserve. Although we must still receive a
new environmental permit from the Colombian Ministry of Environment, we plan to
re-use the Escuela location for the subthrust exploration well. As a result, we
now estimate the cost of drilling and completing this well to be $15 million.
Because we have a 100% working interest in the Deep Dindal association contract,
we will be responsible for the entire cost of drilling and testing the well. Our
ability to commence drilling of this well in 2001 is subject to 1) securing
financing for the costs of the well, 2) timely receiving the required
environmental permit, and 3) contracting a drilling rig. We plan to commence
drilling this well as soon as possible after these three conditions have been
satisfied, which we expect will be in late-summer 2001.

Rosablanca exploration well - We plan to drill an exploration well on the
Rosablanca association contract located in Colombia's Magdalena Valley,
approximately 220 miles north of the Guaduas Oil Field. This well was scheduled
to commence before February 28, 2001 to satisfy certain obligations under the
Rosablanca contract. However, we have not received the required environmental
permit from the Colombian Ministry of Environment. Ecopetrol recently granted a
6-month extension on our obligation as a result of this delay. This well, to be
called the Santa Fe - 1 well, will be drilled to an estimated total depth of
3400 feet at an estimated gross cost of $1.0 million, of which we are
responsible for 100%.

Tres Pasos 16 exploration well - During the third quarter of 2001, we plan to
commence drilling of the Tres Pasos 16 exploration well to test the west side of
the Guaduas Oil Field structure. This well will satisfy the sixth-year
exploration obligation under the Rio Seco association contract. We estimate the
gross cost of this well will be $5.5 million, or $3.0 million net to Seven Seas.

In summary, our planned exploration strategy in 2001 provides for the
drilling of three exploration wells at a gross cost of approximately $22
million, our share of which is approximately $19 million. Coupled with our
development strategy, the gross total of planned capital expenditures in 2001 is
approximately $68 million, our share of which is approximately $46 million. Our
ability to fully implement our exploration and development strategy is subject
to 1) securing financing for our share of costs, 2) timely receiving required
environmental permits, 3) contracting the required oil and gas services and
equipment, and 4) completing the Guaduas - La Dorada pipeline and commencing
pipeline production. For additional information on our financing plans, see the
next section "-- Financing Our Current Strategy".

FINANCING OUR CURRENT STRATEGY

In December 2000, we entered into a $10 million loan agreement with
Stillwater National Bank and Trust Company, N.A. On March 30, 2001, the loan's
maturity date was extended from December 31, 2001 to April 1, 2002. The
Stillwater National Bank loan is secured by all of the stock of the operating
subsidiaries of Seven Seas and is guaranteed by Robert A. Hefner III, chairman
and chief executive officer of Seven Seas. Mr. Hefner received remuneration of
$62,500 for his guarantee. The loan carries a coupon of the Prime Rate plus
.75%, and interest is payable monthly until the loan is due in full on April 1,
2002. Seven Seas intends to use these funds for working capital and plans to
replace, without penalty, this non-convertible loan with the proceeds from a
larger financing planned for 2001. Proceeds from the financing could also be
used to finance the $6.9 million interest payment that will be due on November
15, 2001 on our $110 million senior notes.

Furthermore, we believe that once the pipeline is built and is actually
producing at the rate of between 8,000 BOPD and 10,000 BOPD, additional funds
could be borrowed from the same or other lender(s) to finance a portion of the
development costs necessary to bring production up to 25,000 BOPD. At this time,
we do not know what percent or how much of our revenue will have to be dedicated
to service the pipeline debt. However, we intend to arrange this financing in
such a way that loan proceeds and cash flow reserves will be sufficient to meet
our $6.9 million interest payment due on November 15, 2001 for our $110 million
senior notes.

Non-discretionary capital commitments for the year 2001 are the costs of
constructing the pipeline (for an initial production rate of between 8,000 BOPD
and 10,000 BOPD), drilling an exploratory well on the Rio Seco block, drilling
an exploratory well on the Rosablanca block and the November 15, 2001 interest
obligation for the $110 million senior notes. In the event we are unable to
assign our interest in the Tapir association contract, we may be responsible for
our proportionate share of all or a portion of the costs of the 2001 work
program. See "Properties - Colombian Properties - Tapir association contract".
The following table reflects our currently planned capital expenditures through
the year 2001.

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24

ESTIMATED COST
----------------------------
DESCRIPTION OF PROJECT/EXPENDITURE GROSS NET TO US STATUS
- ---------------------------------- ------- --------- ------
(IN THOUSANDS)

Pipeline and production facilities................ $24,000 $13,848 Construction underway.
Exploratory well - Rosablanca block............... $ 1,000 $ 1,000 Obligation
Exploratory well - Tres Pasos 16.................. $ 5,500 $ 3,025 Obligation
Senior Note 11/15/01 Interest Payment............. $ 6,875 $ 6,875 Due 11/15/01
Tapir working program (2)......................... $ 2,129 $ 2,129 Potential obligation
------- -------
Non-Discretionary Sub-Total............ $39,504 $26,877
======= =======

2001 Development Drilling Program(1) Discretionary expenditure
(4 development wells, 1 injector well)............ $22,000 $12,694 subject to financing
Subthrust exploration well........................ $15,000 $15,000 Discretionary expenditure
subject to financing
------- -------
Discretionary Sub-Total................ $37,000 $27,694
======= =======

Grand Total............................ $76,504 $54,571

- ----------

(1) 2001 development drilling program is part of a two-year plan that has
Guaduas Oil Field partner approval to increase pipeline production from
its initial rate of 8,000 - 10,000 BOPD to 25,000 BOPD. Under this
plan, we will drill an additional 5 development wells in 2002 at a
gross cost of approximately $22 million, or $12.7 net to Seven Seas.

(2) In the event we are unable to assign our interest in the Tapir
association contract, we may be obligated to participate in all or a
portion of the 2001 work program.

Possible sources of financing include:

o commercial bank borrowing;

o industry joint ventures or similar arrangement with industry service and
supplies companies;

o forward sales of oil; and

o debt and equity financing.

All debt financing will be on a secured basis. Under the terms of our $110
million senior notes, we are permitted to incur general indebtedness that can be
senior to our senior notes not exceeding the greater of (i) $25 million, or (ii)
the sum of 100% of our cash and cash equivalents, plus 100% of our receivables
from Ecopetrol, and plus 30% of our discounted future net revenues from proved
oil and gas reserves prepared in accordance with the rules of the United States
Securities and Exchange Commission. As of December 31, 2000, the maximum
permitted amount of secured borrowing was approximately $130.3 million. We are
also authorized under the terms of the senior notes to borrow an additional $10
million for project financing, such as to pay the purchase price or construction
costs of the pipeline and production facilities. We have plans to seek
approximately $45 million in new financing; however, there are no assurances
that we will be successful.

LIQUIDITY AND CAPITAL RESOURCES

WORKING CAPITAL

We had working capital, net of restricted investments, of $12.7 million,
including unrestricted cash and cash equivalents of $12.1 million as of December
31, 2000. Our non-discretionary capital commitments for 2001 are approximately
$17.9 million, not including a potential obligation on the Tapir association
contract discussed above. Additionally, we have a $6.9 million interest payment
due on November 15, 2001. Our non-discretionary expenditures in 2001 total $24.8
million, not including a potential obligation on the Tapir block. We plan to use
our available cash as set forth under "Business -- Our Current Strategy". See
also "-- Financing Our Current Strategy"

EQUITY AND FINANCING ACTIVITIES

As of December 31, 2000, we had 37,836,420 common shares, par value of
$0.001, outstanding, of which none are restricted. At December 31, 2000, we had
outstanding $110.0 million of 12 1/2 % senior notes due May 15, 2005.

In accordance with the terms of the senior notes, we were required to hold
in a separate account or in escrow monies to provide for the first three years
of interest payable under the senior notes. We purchased $13.5 million in U.S.
government securities from the proceeds of the senior notes and deposited the
securities in a segregated account. The amount deposited into the segregated
account was enough to pay the first two interest payments. We also purchased and
pledged $25 million of U.S. government securities to ensure payment of the four
scheduled interest payments on the notes from November 15, 1999 through May 15,
2001. As of December 31, 2000, after making five interest payments, we had $6.7
million in U.S. government securities remaining, which is sufficient to pay
interest on the senior notes through May 2001.

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25

Our activities from inception through December 31, 2000 were funded
primarily by the proceeds from private placements of our securities, including
our common shares, warrants and notes, resulting in aggregate cash proceeds of
$157.0 million. Recent transactions include:

o Exchangeable Notes. In August 1997, we issued $25.0 million of 6%
exchangeable notes in a private transaction with institutional and
accredited investors. The exchangeable notes accrued interest at a rate of
6% per annum and were payable on December 31 and June 30 in each year. The
exchangeable notes were scheduled to mature on August 7, 2003.

o Convertible Debentures. The exchangeable notes were exchanged for a like
principal amount of 6% convertible debentures on August 5, 1998. The 6%
convertible debentures were converted on August 6, 1998 into units
consisting of 2,173,901 common shares and warrants exercisable for
1,086,957 common shares.

o Purchase Warrants. On February 5, 1999, purchase warrants for $1.1 million
of our common shares expired without exercise. We received proceeds of $0.3
million from the exercise of 18,913 warrants. These purchase warrants had
been issued in association with the exchange and conversion of our
previously outstanding $25.0 million issue of 6% exchangeable notes.

o Senior Notes. In May 1998, we completed the offering of $110 million of
12 1/2% senior notes due May 15, 2005 and received net proceeds of
approximately $106 million. Approximately $37.8 million of the proceeds was
held in a separate account or in escrow to provide for the first three years
of interest payable under the senior notes. Interest on the senior notes is
payable semi-annually on May 15 and November 15 of each year. The escrow
account is sufficient to pay interest through May 2001. The senior notes
mature on May 15, 2005. The senior notes are redeemable at our option, in
whole or in part, at any time on or after May 15, 2002, at the prescribed
redemption price, plus accrued and unpaid interest, liquidated damages and
additional amounts, if any, to the date of redemption.

o Stillwater National Bank Loan. In December 2000, we entered into a $10
million loan agreement with Stillwater National Bank and Trust Company, N.A.
On March 30, 2001, the loan's maturity date was extended from December 31,
2001 to April 1, 2002. The Stillwater National Bank loan is secured by all
of the stock of the operating subsidiaries of Seven Seas and is guaranteed
by Robert A. Hefner III, chairman and chief executive officer of Seven Seas.
Mr. Hefner received remuneration of $62,500 for his guarantee. The loan
bears interest at an annual rate of the Prime Rate plus .75%, and interest
is payable monthly until the loan is due in full on April 1, 2002. Seven
Seas intends to use these funds for working capital and plans to replace,
without penalty, this non-convertible loan with the proceeds from a larger
financing planned for 2001. As of the date of this filing, we had drawn $3
million on this loan.

At any time prior to May 15, 2001, we may redeem up to 33 1/3% of the
original aggregate principal amount of the $110 million senior notes at a
redemption price of 112.50% of the principal amount redeemed with a portion of
the net proceeds of an equity or strategic investor offering, provided that at
least 66 2/3% of the original aggregate principal amount of the senior notes
remains outstanding immediately after the redemption. In the event of certain
changes affecting withholding taxes applicable to certain payments on the senior
notes, the senior notes may be redeemed at our option, in whole but not in part,
at any time at a redemption price equal to 100% of the principal amount thereof
plus accrued and unpaid interest, liquidated damages and additional amounts, if
any, to the redemption date. Upon the occurrence of a change of control:

1) unless we redeem the senior notes as provided in (2) below, we will be
required to offer to purchase the senior notes at a purchase price equal
to 101% of the aggregate principal amount thereof, plus accrued and
unpaid interest, liquidated damages and additional amounts, if any, to
the date of purchase; and

2) we will have the option, at any time prior to May 15, 2002, to redeem
the senior notes, in whole but not in part, at a redemption price equal
to 100% of the principal amount thereof plus the applicable premium and
accrued and unpaid interest, liquidated damages and additional amounts,
if any, to the date of redemption.

The senior notes are senior obligations of Seven Seas and are ranked equally
in right and priority of payment with all of our existing and future senior
indebtedness.

If our cash flow from operations is not sufficient to pay principal and
interest on our debt when due, we would have to attempt to restructure or
refinance the debt or sell assets to obtain funds.

CAPITAL SPENDING

From inception through December 31, 2000, we had cash expenditures for the
exploration of oil and gas properties of $121.3 million.

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26

ACCOUNTING POLICIES AND DEVELOPMENT STAGE ACCOUNTING

The consolidated financial statements and notes thereto included in this
document have been prepared in accordance with generally accepted accounting
principles in the United States.

Our exploration and development activities have not generated a substantial
amount of revenue, thus requiring the financial statements to be presented as a
development stage enterprise. Accumulated losses are presented on the balance
sheet as "Deficit accumulated during the development stage." The income
statement presents revenues and expenses for each period presented and also a
cumulative total of both amounts from our inception. Period-to-period
comparisons of such results and certain financial data may not be meaningful or
indicative of future results. In this regard, future results of Seven Seas will
be highly dependent upon the success of our Guaduas Oil Field operations. The
statement of cash flows shows inflows and outflows for each period presented and
from our inception. In addition, the Notes to Consolidated Financial Statements
are required to identify the enterprise as development stage.

We follow the full-cost method of accounting for oil and natural gas
properties. Under this method, all costs incurred in the acquisition,
exploration and development of oil and gas properties, including unproductive
wells, are capitalized in separate cost centers for each country. Such
capitalized costs include contract and concession acquisition, geological,
geophysical and other exploration work, drilling, completing and equipping oil
and gas wells, constructing production facilities and pipelines, and other
related costs. We capitalized general and administrative costs of $0.2 million,
$0.3 million, and $0.3 million in 2000, 1999, and 1998, respectively. We
capitalized interest of $13.2 million, $13.8 million and $9.8 million in 2000,
1999 and 1998 respectively.

The capitalized costs of oil and gas properties in each cost center are
amortized on the composite units of production method based on future gross
revenues from proved reserves. Sales or other dispositions of oil and gas
properties are normally accounted for as adjustments of capitalized costs. Gain
or loss is not recognized in income unless a significant portion of a cost
center's reserves are involved. Capitalized costs associated with the
acquisition and evaluation of unproved properties are excluded from amortization
until it is determined whether proved reserves can be assigned to such
properties or until the value of the properties is impaired. If the net
capitalized costs of oil and gas properties in a cost center exceed an amount
equal to the sum of the present value of estimated future net revenues from
proved oil and gas reserves in the cost center and the lower of cost or fair
value of properties not being amortized, both adjusted for income tax effects,
such excess is charged to expense.

RESULTS OF DEVELOPMENT STAGE OPERATIONS

YEARS ENDED DECEMBER 31, 2000, 1999 AND 1998

Revenues from oil sales were $4.6 million, $2.3 million and $0.02 million in
2000, 1999 and 1998, respectively. Lease operating expenses were $2.6 million,
$2.5 million and $0.9 million in 2000, 1999 and 1998, respectively. The $2.3
million and $0.1 million increase during 2000 in oil and gas revenues and lease
operating expenses, respectively, was due to the commencement of
post-exploration phase production in August 2000.

Oil production in Colombia (net to us, including minority interest through
June 30, 1999) of 189,988 barrels, 199,216 barrels and 1,997 barrels in 2000,
1999 and 1998, respectively, pertaining solely to our share of oil produced, was
sold to Refinerie del Nare and Ecopetrol at an average price of $25.02 per
barrel in 2000, $12.50 per barrel in 1999 and $8.14 per barrel in 1998.

Interest income was $1.8 million, $3.1 million and $3.8 million in 2000,
1999 and 1998, respectively. The decrease from 1999 to 2000 was the consequence
of lower cash and investment balances resulting from the use of funds from the
issuance of the senior notes in May 1998.

General and administrative costs were $7.3 million, $7.7 million and $9.8
million in 2000, 1999 and 1998, respectively. Non-reoccurring general and
administrative costs in 2000 amounted to $1.3 and were related to the migration
of the Company to the Cayman Islands from the Yukon Territory and severance paid
to certain employees as part of the Company's reorganization of its Bogota
office. The costs incurred during 1998 included $2.1 million relating to costs
incurred conducting feasibility studies for the proposed construction of
pipeline and production facilities and other development activities in Colombia.

Depletion, depreciation and amortization was $1.7 million, $1.8 million and
$0.7 million in 2000, 1999 and 1998, respectively. We began recording depletion
of our proved oil and gas properties in the fourth quarter 1999, resulting in
increased amounts in 2000 and 1999.

As required under the full cost method of accounting, capitalized costs are
limited to the sum of (1) the present value of future net revenues, using
current unescalated pricing and discounted at 10% per annum from proved reserves
and (2) the lower of cost or estimated fair value of unevaluated properties, all
net of expected income tax effects. There was no write-down in 1999 or 2000. At
December 31, 1998, we recognized a non-cash write-down of oil and gas properties
in the amount of $129.8 million pre-tax or $84.4 million after tax pursuant to
this ceiling limitation. The write-down was primarily the result of the decline
in crude oil prices and the

26
27

impairment of unevaluated properties due primarily to the failure of five
non-commercial exploratory wells.

Seven Seas incurred net losses of $5.9 million, $6.8 million and $90.2
million for the years ended December 31, 2000, 1999 and 1998, respectively. The
1998 loss includes a non-cash write-down of $129.8 million pre-tax. The
write-down of oil and gas properties reduced the temporary differences included
in deferred tax liabilities resulting in an income tax benefit of $45.4 million
and a write-down after taxes of $84.4 million.

TAXES

Our net income, as defined under Colombian law, from Colombian sources is
subject to Colombian corporate income tax at a rate of 35%. An additional
remittance tax is imposed upon remittance of profits abroad at a rate of 7%.

During 2000, we were also subject to income taxes in Canada and the United
States, where the statutory rates were 45% and 35% respectively. The Company had
United States income tax expense of $0.04 million in 2000 and $0.06 million in
1999.

FORWARD-LOOKING INFORMATION

From time to time, Seven Seas may make certain statements that provide
shareholders and the investing public with "forward-looking" information as
defined by the federal securities laws. Words such as "anticipate," "assume,"
"believe," "estimate," "project," and similar expressions are intended to
identify such forward-looking statements. Forward-looking statements may be made
by management orally or in writing, including, but not limited to, in press
releases, as part of this "Management's Discussion and Analysis of Financial
Condition and Results of Operations" section and as part of other sections of
Seven Seas' filings with the U.S. Securities and Exchange Commission. Such
forward-looking statements may include, but not be limited to, statements
concerning estimates of current and future results of operations, financial
position, reserves, the timing and commencement of wells and development plans,
drilling results as indicated by log analysis, core samples, examination of
cuttings, hydrocarbons shows while drilling and production estimates from wells
drilled based upon drill stem tests and other test data, future capacity under
credit arrangements, future capital expenditures, liquidity requirements and
liquidity sufficiency.

Such forward-looking statements are subject to certain risks, uncertainties
and assumptions, including without limitation, those defined below. Should one
or more of these risks or uncertainties materialize, or should any of the
underlying assumptions prove incorrect, actual results of current and future
operations may vary materially from those anticipated, estimated or projected.

Among the factors that have a direct bearing on Seven Seas' results of
operations and the oil and gas industry in which it operates are uncertainties
inherent in estimating oil and gas reserves and future hydrocarbon production
and cash flows, particularly with respect to wells that have not been fully
tested and with wells having limited production testing histories; access to
additional capital; changes in the price of oil and natural gas, services and
equipment; the limited exploration of the concessions; the status of existing
and future contractual relationships with Ecopetrol; foreign currency
fluctuation risks; Seven Seas' substantial indebtedness, the presence of
competitors with greater financial resources and capacity; and difficulties and
risks associated with operating in Colombia.

ITEM 7A. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK

We are exposed to market risk, including adverse changes in commodity
prices, interest rates and foreign currency exchange rates as discussed below.

Commodity risk

Interest rate risk

We consider our interest rate risk exposure to be minimal as a result of a
fixed interest rate on the $110 million 12 1/2% Senior Notes. We currently have
no open interest rate swap agreements.

Foreign currency exchange rate risk

We conduct business in several foreign currencies and are subject to foreign
currency exchange rate risk on cash flows related to sales, expenses and capital
expenditures. However, because predominately all transactions in our existing
foreign operations are denominated in U.S. dollars, the U.S. dollar is the
functional currency for all operations.

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28

ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA

INDEX TO CONSOLIDATED FINANCIAL STATEMENTS

PAGE
----

Seven Seas Petroleum Inc. and Subsidiaries
Report of Independent Public Accountants....................... 29
Consolidated Balance Sheets as of December 31, 2000
and 1999..................................................... 30
Consolidated Statements of Operations and Accumulated
Deficit for the years ended December 31, 2000, 1999
and 1998 and from Inception (February 3, 1995) to
December 31, 2000............................................ 31
Consolidated Statement of Stockholders' Equity for the
period from Inception (February 3, 1995) to December 31,
2000......................................................... 32
Consolidated Statements of Cash Flows for the years ended
December 31, 2000, 1999 and 1998 and from Inception
(February 3, 1995) to December 31, 2000...................... 33
Notes to Consolidated Financial Statements..................... 34

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29

REPORT OF INDEPENDENT PUBLIC ACCOUNTANTS

To Seven Seas Petroleum Inc.:

We have audited the accompanying consolidated balance sheets of Seven Seas
Petroleum Inc. (a Cayman Islands company in the development stage, formerly a
Yukon Territory Canada corporation, see Note 1) and subsidiaries as of December
31, 2000 and 1999, and the related consolidated statements of operations and
accumulated deficit, stockholders' equity, and cash flows for the years ended
December 31, 2000, 1999 and 1998 and for the period from inception (February 3,
1995) to December 31, 2000. These financial statements are the responsibility of
the Company's management. Our responsibility is to express an opinion on these
financial statements based on our audits.

We conducted our audits in accordance with auditing standards generally accepted
in the United States. Those standards require that we plan and perform the audit
to obtain reasonable assurance about whether the financial statements are free
of material misstatement. An audit includes examining, on a test basis, evidence
supporting the amounts and disclosures in the financial statements. An audit
also includes assessing the accounting principles used and significant estimates
made by management, as well as evaluating the overall financial statement
presentation. We believe that our audits provide a reasonable basis for our
opinion.

In our opinion, the consolidated financial statements referred to above present
fairly, in all material respects, the financial position of Seven Seas Petroleum
Inc. and subsidiaries as of December 31, 2000 and 1999, and the results of their
operations and their cash flows for the years ended 2000, 1999 and 1998 and for
the period from inception to December 31, 2000 in conformity with accounting
principles generally accepted in the United States.

The accompanying financial statements have been prepared assuming that the
Company will continue as a going concern. As discussed in Note 1 to the
financial statements, the Company has suffered recurring losses from operations,
has a net capital deficiency, is highly dependent on cash flows from a single
production area that has a limited history and may have to seek additional
financing to meet its existing commitments and operating needs. These matters
raise substantial doubt about the Company's ability to continue as a going
concern. Management's plans in regard to these matters are also described in
Note 1 to the financial statements. The financial statements do not include any
adjustments that might result from the outcome of this uncertainty.

ARTHUR ANDERSEN LLP

Houston, Texas
March 30, 2001

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30

SEVEN SEAS PETROLEUM INC. AND SUBSIDIARIES
(A DEVELOPMENT STAGE ENTERPRISE)

CONSOLIDATED BALANCE SHEETS
(IN THOUSANDS, EXCEPT SHARE DATA)

DECEMBER 31,
------------------------
2000 1999
---------- ----------

ASSETS

CURRENT ASSETS
Cash and cash equivalents ..................................... $ 12,128 $ 22,447
Short-term investments ........................................ 1,168 --
Restricted short-term investments ............................. 6,734 13,312
Accounts receivable ........................................... 7,297 9,821
Interest receivable ........................................... 55 243
Inventory ..................................................... 563 764
Prepaids and other ............................................ 181 288
---------- ----------
28,126 46,875

Note receivable from related party .............................. 215 435
Restricted long-term investments ................................ -- 6,391
Land ............................................................ 1,071 1,065
Evaluated oil and gas properties, full-cost method, net of
accumulated depletion of $1,497 at December 31, 2000 and $764 at
December 31, 1999 ............................................. 115,609 96,244
Unevaluated oil and gas properties, full-cost method ............ 105,535 105,725
Fixed assets, net of accumulated depreciation of $1,054 at
December 31, 2000 and $669 at December 31, 1999 ............... 840 1,060
Other assets, net of accumulated amortization of $1,675 at
December 31, 2000 and $1,068 at December 31, 1999 ............. 2,680 3,287
---------- ----------
TOTAL ASSETS .......................................... $ 254,076 $ 261,082
========== ==========

LIABILITIES AND STOCKHOLDERS' EQUITY

CURRENT LIABILITIES
Accounts payable .............................................. $ 6,896 $ 7,917
Interest payable .............................................. 1,719 1,719
Other accrued liabilities ..................................... 89 78
---------- ----------
8,704 9,714

Long-term debt .................................................. 110,000 110,000
Deferred income taxes ........................................... 24,703 24,794

COMMITMENTS AND CONTINGENCIES (Note 12)

STOCKHOLDERS' EQUITY
Share capital--
Authorized unlimited common shares par value $0.001 per share;
37,836,420 and 37,833,420 issued and outstanding at
December 31, 2000 and 1999, respectively ................... 225,807 225,805
Deficit accumulated during development stage .................. (115,138) (109,231)

Treasury stock; 29 shares held at December 31, 2000 and
1999 ....................................................... -- --
---------- ----------
Total Stockholders' Equity ............................ 110,669 116,574
---------- ----------

TOTAL LIABILITIES AND STOCKHOLDERS' EQUITY ............ $ 254,076 $ 261,082
========== ==========

The accompanying notes are an integral part of these financial statements.

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31

SEVEN SEAS PETROLEUM INC. AND SUBSIDIARIES
(A DEVELOPMENT STAGE ENTERPRISE)

CONSOLIDATED STATEMENTS OF OPERATIONS AND ACCUMULATED DEFICIT
(IN THOUSANDS, EXCEPT SHARE DATA)

CUMULATIVE
TOTAL FROM
INCEPTION
(FEBRUARY 3,
YEAR ENDED DECEMBER 31, 1995) TO
-------------------------------------------- DECEMBER 31,
2000 1999 1998 2000
------------ ------------ ------------ ------------

REVENUE
Crude oil sales ..................................... $ 4,632 $ 2,261 $ 16 $ 7,922
Interest income ..................................... 1,802 3,052 3,781 9,916
------------ ------------ ------------ ------------
6,434 5,313 3,797 17,838
EXPENSES
General and administrative .......................... 7,256 7,683 9,761 36,940
Oil and gas operating expenses ...................... 2,612 2,491 942 7,205
Depletion, depreciation and
amortization ..................................... 1,729 1,825 674 4,525

Interest expense .................................... 558 -- -- 558
Writedown of proved oil & gas
properties ....................................... -- -- 129,789 129,789
Gain (loss) on sale of exploration
properties ....................................... -- 670 (577) 124
Dry hole and abandonment costs ...................... -- -- -- 1,145
Geological and geophysical .......................... -- -- -- 47
Other (income) expense .............................. 146 (36) (97) (12)
------------ ------------ ------------ ------------
12,301 12,633 140,492 180,321
NET LOSS BEFORE INCOME TAXES AND MINORITY
INTEREST ............................................ (5,867) (7,320) (136,695) (162,483)
INCOME TAX PROVISION (BENEFIT) ........................ 40 62 (45,718) (45,616)
------------ ------------ ------------ ------------
NET LOSS BEFORE MINORITY INTEREST ..................... (5,907) (7,382) (90,977) (116,867)
MINORITY INTEREST ..................................... -- 593 778 1,729
------------ ------------ ------------ ------------
NET LOSS .............................................. (5,907) (6,789) (90,199) (115,138)
------------ ------------ ------------ ------------
DEFICIT ACCUMULATED DURING THE
DEVELOPMENT STAGE, beginning of
period .............................................. (109,231) (102,442) (12,243) --
------------ ------------ ------------ ------------
DEFICIT ACCUMULATED DURING THE
DEVELOPMENT STAGE, end of period .................... $ (115,138) $ (109,231) $ (102,442) $ (115,138)
============ ============ ============ ============
BASIC AND DILUTED NET LOSS PER COMMON
SHARE ............................................... $ (0.16) $ (0.18) $ (2.49) $ (4.11)
============ ============ ============ ============
WEIGHTED AVERAGE COMMON SHARES
OUTSTANDING ......................................... 37,835,780 37,861,984 36,203,713 28,044,604
============ ============ ============ ============

The accompanying notes are an integral part of these financial statements.

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32
SEVEN SEAS PETROLEUM INC. AND SUBSIDIARIES
(A DEVELOPMENT STAGE ENTERPRISE)

CONSOLIDATED STATEMENTS OF STOCKHOLDERS' EQUITY
FOR THE PERIOD FROM INCEPTION (FEBRUARY 3, 1995) THROUGH DECEMBER 31, 2000
(IN THOUSANDS, EXCEPT SHARE DATA)

COMMON STOCK PREFERRED STOCK
-------------------------- ---------------------------
DATE NUMBER AMOUNT NUMBER AMOUNT
--------------------- ------------ ------------ ------------ ------------

Issuance of common share to founder .............. February 3, 1995 1 $ -- -- $ --
Issuance of common shares to founder for cash .... February 27, 1995 999,999 -- -- --
Issuance of common shares in a private
placement for cash ($0.25 per share) ............ March 22, 1995 4,000,000 1,000 -- --
Issuance of common shares in private
placements for cash ($0.75 per share): .......... May 31, 1995 5,687,666 4,266 -- --
June 9, 1995 979,000 734 -- --
Issuance of common shares in settlement of
agents' fees ($0.75 per share): ................. May 31, 1995 284,383 213 -- --
June 9, 1995 48,950 37 -- --
Less: Common share issuance cost ................. May 31 - June 9, 1995 -- (250) -- --
Issuance of common shares in connection with
the May 5, 1995 amalgamation agreement with
Rusty Lake Resources ($0.25 per share) .......... June 29-30, 1995 680,464 170 -- --
Net loss ......................................... -- -- -- --
------------ ------------ ------------ ------------
BALANCE AT DECEMBER 31, 1995 ..................... 12,680,463 6,170 -- --
Issuance of special warrants in a brokered
private placement for cash ($2.75 per warrant) .. March 15, 1996 -- -- -- --
Issuance of common shares to the Company's
401(k) plan ($7.875 per share) .................. April 29,1996 10,000 79 -- --
Purchase Treasury Stock ($8.00 per share) ........ June 26, 1996 -- -- -- --
Exercise of stock options for cash ($.75 per
share) .......................................... Jan. - June 1996 305,000 229 -- --
Exercise of stock options for cash ($7.125
per share) ...................................... April 29, 1996 10,000 71 -- --
Issuance of exchangeable preferred stock in
connection with business combination
($9.125 per share) .............................. July 26, 1996 -- -- 5,002,972 45,652
Issuance of special warrants in connection
with business combination ($9.125 per warrant) .. July 26, 1996 -- -- -- --
Issuance of convertible special warrants in
a brokered private placement for cash
($15.00 per warrant) ............................ October 16, 1996 -- -- -- --
Exercise of stock options for cash ($.75 per
share) .......................................... July - December 1996 310,333 233 -- --
Net loss ......................................... -- -- -- --
------------ ------------ ------------ ------------
BALANCE AT DECEMBER 31, 1996 ..................... 13,315,796 6,782 5,002,972 45,652
Conversion of special warrants issued in
connection with the business combination
dated July 26, 1996 ($9.125 per share) .......... February 7, 1997 11,774,171 107,439 -- --
Conversion of the preferred shares in
connection with the business combination
dated July 26, 1996 ($9.125 per share) .......... February 7, 1997 5,002,972 45,652 (5,002,972) (45,652)
Conversion of privately placed special
warrants ($15.00 per warrant) ................... February 7, 1997 500,000 7,013 -- --
Conversion of privately placed special
warrants ($2.75 per warrant) .................... February 7, 1997 2,000,000 5,096 -- --
Issuance of common shares in connection with
the business combination ($18.55 per share) ..... March 5, 1997 1,000,000 18,550 -- --
Conversion of privately placed special
warrants for cash ($3.50 per warrant) ........... March 14, 1997 1,000,000 3,500 -- --
Exercise of stock options ($.75-- 10.90 per
share) .......................................... Jan. - Dec 1997 478,667 2,374 -- --
Net loss ......................................... -- -- -- --
------------ ------------ ------------ ------------
BALANCE AT DECEMBER 31, 1997 ..................... 35,071,606 196,406 -- --
Exercise of stock options ($.75-- $10.90 per
share) .......................................... Jan. - Dec. 1998 514,000 5,351 -- --
Conversion of debentures ($11.50 per share,
$2.90 per warrant) .............................. August 6, 1998 2,173,901 20,351 -- --
Exercise of warrants ($15.00 per share) .......... August 12, 1998 18,913 339 -- --
Net loss ......................................... -- -- -- --
------------ ------------ ------------ ------------
BALANCE AT DECEMBER 31, 1998 ..................... 37,778,420 222,447 -- --
Expiration of warrants ........................... February 5, 1999 -- 3,093 -- --
Stock issuance ($4.8125 per share) ............... April 1, 1999 55,000 265 -- --
Net loss ......................................... -- -- -- --
------------ ------------ ------------ ------------
BALANCE AT DECEMBER 31, 1999 ..................... 37,833,420 $ 225,805 -- $ --
============ ============ ============ ============
Exercise of stock options ($.75 per share) ....... Jan. - Dec. 2000 3,000 2 -- --
Net loss ......................................... -- -- -- --
------------ ------------ ------------ ------------
BALANCE AT DECEMBER 31, 2000 ..................... 37,836,420 $ 225,807 -- $ --
============ ============ ============ ============

SPECIAL WARRANTS TREASURY STOCK
--------------------------- --------------------------
NUMBER AMOUNT NUMBER AMOUNT
------------ ------------ ------------ ------------

Issuance of common share to founder ............... -- $ -- --
Issuance of common shares to founder for cash ..... -- -- -- --
Issuance of common shares in a private
placement for cash ($0.25 per share) ............. -- -- -- --
Issuance of common shares in private
placements for cash ($0.75 per share): ........... -- -- -- --
-- -- -- --
Issuance of common shares in settlement of
agents' fees ($0.75 per share): .................. -- -- -- --
-- -- -- --
Less: Common share issuance cost .................. -- -- -- --
Issuance of common shares in connection with
the May 5, 1995 amalgamation agreement with
Rusty Lake Resources ($0.25 per share) ........... -- -- -- --
Net loss .......................................... -- -- -- --
------------ ------------ ------------ ------------
BALANCE AT DECEMBER 31, 1995 ...................... -- -- -- --
Issuance of special warrants in a brokered
private placement for cash ($2.75 per warrant) ... 2,000,000 5,096 -- --
Issuance of common shares to the Company's
401(k) plan ($7.875 per share) ................... -- -- -- --
Purchase Treasury Stock ($8.00 per share) ......... -- -- 29 --
Exercise of stock options for cash ($.75 per
share) ........................................... -- -- -- --
Exercise of stock options for cash ($7.125
per share) ....................................... -- -- -- --
Issuance of exchangeable preferred stock in
connection with business combination
($9.125 per share) ............................... -- -- -- --
Issuance of special warrants in connection
with business combination ($9.125 per warrant) ... 11,774,171 107,439 -- --
Issuance of convertible special warrants in
a brokered private placement for cash
($15.00 per warrant) ............................. 500,000 7,013 -- --
Exercise of stock options for cash ($.75 per
share) ........................................... -- -- -- --
Net loss .......................................... -- -- -- --
------------ ------------ ------------ ------------
BALANCE AT DECEMBER 31, 1996 ...................... 14,274,171 119,548 29 --
Conversion of special warrants issued in
connection with the business combination
dated July 26, 1996 ($9.125 per share) ........... (11,774,171) (107,439) -- --
Conversion of the preferred shares in
connection with the business combination
dated July 26, 1996 ($9.125 per share) ........... -- -- -- --
Conversion of privately placed special
warrants ($15.00 per warrant) .................... (500,000) (7,013) -- --
Conversion of privately placed special
warrants ($2.75 per warrant) ..................... (2,000,000) (5,096) -- --
Issuance of common shares in connection with
the business combination ($18.55 per share) ...... -- -- -- --
Conversion of privately placed special
warrants for cash ($3.50 per warrant) ............ -- -- -- --
Exercise of stock options ($.75 -- 10.90 per
share) ........................................... -- -- -- --
Net loss .......................................... -- -- -- --
------------ ------------ ------------ ------------
BALANCE AT DECEMBER 31, 1997 ...................... -- -- 29 --
Exercise of stock options ($.75 -- $10.90 per
share) ........................................... -- -- -- --
Conversion of debentures ($11.50 per share,
$2.90 per warrant) ............................... 1,086,957 3,148 -- --
Exercise of warrants ($15.00 per share) ........... (18,913) (55) -- --
Net loss .......................................... -- -- -- --
------------ ------------ ------------
BALANCE AT DECEMBER 31, 1998 ...................... 1,068,044 3,093 29 --
Expiration of warrants ............................ (1,068,044) (3,093) -- --
Stock issuance ($4.8125 per share) ................ -- -- -- --
Net loss .......................................... -- -- -- --
------------ ------------ ------------ ------------
BALANCE AT DECEMBER 31, 1999 ...................... -- $ -- 29 --
============ ============ ============ ============
Exercise of stock options ($.75 per share) ........ -- -- -- --
Net loss .......................................... -- -- -- --
------------ ------------ ------------ ------------
BALANCE AT DECEMBER 31, 2000 ...................... -- $ -- 29 --
============ ============ ============ ============

DEFICIT
ACCUMULATED
DURING
DEVELOPMENT
PHASE TOTAL
------------ ------------

Issuance of common share to founder ............... $ -- $ --
Issuance of common shares to founder for cash ..... -- --
Issuance of common shares in a private
placement for cash ($0.25 per share) ............. -- 1,000
Issuance of common shares in private
placements for cash ($0.75 per share): ........... -- 4,266
-- 734
Issuance of common shares in settlement of
agents' fees ($0.75 per share): .................. -- 213
-- 37
Less: Common share issuance cost .................. -- (250)
Issuance of common shares in connection with
the May 5, 1995 amalgamation agreement with
Rusty Lake Resources ($0.25 per share) ........... -- 170
Net loss .......................................... (2,120) (2,120)
------------ ------------
BALANCE AT DECEMBER 31, 1995 ...................... (2,120) 4,050
Issuance of special warrants in a brokered
private placement for cash ($2.75 per warrant) ... -- 5,096
Issuance of common shares to the Company's
401(k) plan ($7.875 per share) ................... -- 79
Purchase Treasury Stock ($8.00 per share) ......... -- --
Exercise of stock options for cash ($.75 per
share) ........................................... -- 229
Exercise of stock options for cash ($7.125
per share) ....................................... -- 71
Issuance of exchangeable preferred stock in
connection with business combination
($9.125 per share) ............................... -- 45,652
Issuance of special warrants in connection
with business combination ($9.125 per warrant) ... -- 107,439
Issuance of convertible special warrants in
a brokered private placement for cash
($15.00 per warrant) ............................. -- 7,013
Exercise of stock options for cash ($.75 per
share) ........................................... -- 233
Net loss .......................................... (2,195) (2,195)
------------ ------------
BALANCE AT DECEMBER 31, 1996 ...................... (4,315) 167,667
Conversion of special warrants issued in
connection with the business combination
dated July 26, 1996 ($9.125 per share) ........... -- --
Conversion of the preferred shares in
connection with the business combination
dated July 26, 1996 ($9.125 per share) ........... -- --
Conversion of privately placed special
warrants ($15.00 per warrant) .................... -- --
Conversion of privately placed special
warrants ($2.75 per warrant) ..................... -- --
Issuance of common shares in connection with
the business combination ($18.55 per share) ...... -- 18,550
Conversion of privately placed special
warrants for cash ($3.50 per warrant) ............ -- 3,500
Exercise of stock options ($.75-- 10.90 per
share) ........................................... -- 2,374
Net loss .......................................... (7,928) (7,928)
------------ ------------
BALANCE AT DECEMBER 31, 1997 ...................... (12,243) 184,163
Exercise of stock options ($.75-- $10.90 per
share) ........................................... -- 5,351
Conversion of debentures ($11.50 per share,
$2.90 per warrant) ............................... -- 23,499
Exercise of warrants ($15.00 per share) ........... -- 284
Net loss .......................................... (90,199) (90,199)
------------ ------------
BALANCE AT DECEMBER 31, 1998 ...................... (102,442) 123,098
Expiration of warrants ............................ -- --
Stock issuance ($4.8125 per share) ................ -- 265
Net loss .......................................... (6,789) (6,789)
------------ ------------
BALANCE AT DECEMBER 31, 1999 ...................... $ (109,231) $ 116,574
============ ============
Exercise of stock options ($.75 per share) ........ -- 2
Net loss .......................................... (5,907) (5,907)
------------ ------------
BALANCE AT DECEMBER 31, 2000 ...................... $ (115,138) $ (110,669)
============ ============

The accompanying notes are an integral part of these financial statements.

32
33

SEVEN SEAS PETROLEUM INC. AND SUBSIDIARIES
(A DEVELOPMENT STAGE ENTERPRISE)

CONSOLIDATED STATEMENTS OF CASH FLOWS
(IN THOUSANDS)

OPERATING ACTIVITIES
Net loss ...................................................... $ (5,907) $ (6,789) $ (90,199) $ (115,138)
Add (subtract) items not requiring (providing) cash:
Compensation expense .......................................... -- -- -- 2,140
Minority interest ............................................. -- (593) (778) (1,729)
Common stock contribution to 401(k) retirement plan ........... -- -- -- 79
Depletion, depreciation and amortization ...................... 1,729 1,825 679 4,530
Writedown of proved oil & gas properties ...................... -- -- 129,789 129,789
Gain (loss) on sale of exploration properties ................. -- 670 (577) 124
Dry hole and abandonment costs ................................ -- -- -- 1,140
Gain on sale of marketable securities ......................... -- -- (6) (6)
Loss on sale of fixed assets .................................. 2 -- -- 2
Deferred income tax benefit ................................... (91) 62 (45,727) (45,756)
Amortization of investments ................................... (781) (1,357) -- (2,138)
Changes in working capital excluding changes to cash and
cash equivalents:
Accounts receivable ......................................... 2,524 (1,879) (3,238) (5,035)
Interest receivable ......................................... 188 289 (532) (55)
Inventory ................................................... 201 348 (1,316) (767)
Prepaids and other, net ..................................... 107 (63) (107) (181)
Accounts payable ............................................ (398) 1,381 2,128 4,603
Other accrued liabilities and other ......................... 569 (252) 487 896
------------ ------------ ------------ ------------
Cash Flow Used in Operating Activities ........................ (1,857) (6,358) (9,397) (27,502)
------------ ------------ ------------ ------------
INVESTING ACTIVITIES
Exploration of oil and gas properties ......................... (21,090) (29,958) (47,889) (121,303)
Purchase of land .............................................. (6) (1) (1,257) (1,264)
Purchase of investments ....................................... (1,168) -- (38,301) (39,469)
Proceeds from acquisition ..................................... -- -- -- 630
(Payment to withdraw) proceeds from sale of property .......... -- (250) 1,163 997
Proceeds from sale of marketable securities ................... -- -- 50 50
Proceeds from sale of investments ............................. 13,750 19,955 -- 33,705
Note receivable from employees ................................ 220 (235) -- (215)
Other asset additions ......................................... (170) (239) (1,242) (2,165)
------------ ------------ ------------ ------------
Cash Flow Used in Investing Activities ........................ (8,464) (10,728) (87,476) (129,034)
------------ ------------ ------------ ------------
FINANCING ACTIVITIES
Proceeds from special warrants issued ......................... -- -- 284 12,393
Proceeds from share capital issued ............................ 2 -- 3,972 15,468
Proceeds from additional paid-in capital contributed .......... -- -- -- 1
Proceeds from issuance of long-term debt ...................... -- -- 110,000 135,000
Costs of issuing long-term debt ............................... -- -- (4,248) (5,821)
Contributions by minority interest ............................ -- 1,386 6,945 11,623
------------ ------------ ------------ ------------
Cash Flow Provided by Financing Activities .................... 2 1,386 116,953 168,664
------------ ------------ ------------ ------------
NET INCREASE (DECREASE) IN CASH AND CASH
EQUIVALENTS ................................................. (10,319) (15,700) 20,080 12,128
Cash and cash equivalents, beginning of period ................ 22,447 38,147 18,067 --
------------ ------------ ------------ ------------
CASH AND CASH EQUIVALENTS, END OF PERIOD ...................... $ 12,128 $ 22,447 $ 38,147 $ 12,128
============ ============ ============ ============

Supplemental disclosures of cash flow information:

The Company incurred interest costs of $13.8 million, $13.8 million, and
$9.8 million for the years ended December 31, 2000, 1999 and 1998, respectively,
and $13.2 million, $13.8 million, and $9.8 million was capitalized during the
respective periods.

Cash paid for interest for the years ended December 31, 2000, 1999 and 1998
was $13.8 million, $13.8 million, and $8.1 million, respectively.

The Company paid $100,000, zero, and $30,000 for estimated income taxes
during the year ended December 31, 2000, 1999, and 1998, respectively.

The accompanying notes are an integral part of these financial statements.

33
34

SEVEN SEAS PETROLEUM INC. AND SUBSIDIARIES
(A DEVELOPMENT STAGE ENTERPRISE)

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

1. DEVELOPMENT STAGE OPERATIONS:

FORMATION

Seven Seas Petroleum Inc. (a Cayman Islands exempted company limited by
shares, formerly a Yukon Territory, Canada corporation, Note 15) was formed on
February 3, 1995. Seven Seas Petroleum Inc. and its subsidiaries (collectively
referred to as "Seven Seas" or the "Company") are a development stage enterprise
engaged in the exploration, development and production of oil and natural gas in
Colombia. The Company is the operator of an oil discovery, known as the "Guaduas
Oil Field," which is located in an area defined by the Rio Seco and Dindal
association contracts covering a total of approximately 109,000 contiguous acres
in central Colombia. The Company owns a 57.7% working interest in these two
association contracts before participation by Empresa Colombiana de Petroleos
("Ecopetrol"), the Colombian national oil company. The Company has no
significant income producing properties and its principal assets, its interests
in the association contracts, are in the early stage of exploration and
development.

ACTIVITY TO DATE

As of December 31, 2000, the Company has spent $242.2 million to acquire and
$80.3 million to delineate the reserve potential of the Guaduas Oil Field. The
Company has participated in the drilling of twelve exploratory wells within the
Dindal and Rio Seco association contract areas, seven of which are classified as
oil and gas wells. Four of the twelve did not produce commercial amounts of oil
and gas during testing and one remains to be tested. As of December 31, 2000,
the Guaduas Oil Field had produced a cumulative volume of approximately 1.2
million (0.5 million net to Seven Seas) barrels of oil.

Since inception through December 31, 2000, the Company incurred cumulative
losses of $115.1 million and, because of its continued exploration and
development activities, expects that it will continue to incur losses and that
its accumulated deficit will increase until commencement of production from the
Guaduas Oil Field occurs in quantities sufficient to cover operating expenses.

CURRENT STRATEGY

The Company's strategy for 2001 includes the continued development of the
Guaduas Oil Field and new exploration on its Colombian properties.

DEVELOPMENT

The Company is currently constructing a 36-mile pipeline that will connect
the Guaduas Oil Field to international oil markets via Colombia's existing
pipeline infrastructure. The pipeline will have an initial throughput capacity
of approximately 25,000 barrels of oil per day (BOPD), expandable to
approximately 40,000 BOPD with additional investment. Seven Seas is also
constructing production facilities for production of approximately 25,000 BOPD.
Both the pipeline and production facilities are scheduled for completion in
mid-2001. The gross costs of the pipeline and the production facilities are
approximately $24 million, of which the Company will be responsible for
approximately $13.8 million.

When the pipeline and production facilities are complete, the Company
believes that initial pipeline production, which will be generated by existing
productive wells, will be approximately 8,000 BOPD to 10,000 BOPD. The Company
recently agreed with its Guaduas Oil Field partners to a two-year development
well drilling program that provides for the drilling of nine development wells
and one injector over the course of 2001 and 2002. The Company believes these
wells will increase pipeline production from its initial rates to approximately
25,000 BOPD. In 2001, Seven Seas plans to drill four of these nine development
wells and the one injector well at a gross cost of approximately $22 million,
the Company's share of which is approximately $13 million. The gross cost of the
entire 2001--2002 development well program is estimated to cost approximately
$44 million, the Company's share of which is $25 million.

EXPLORATION

The Company plans to drill three exploration wells in 2001:

1. The Subthrust exploration well to test the subthrust Dindal prospect at
an estimated gross cost of $15 million ($15 million net to the Company)

2. The Santa Fe - 1 on the Rosablanca association contract at an estimated
gross cost of $1.0 million ($1.0 million net to the Company)

3. The Tres Pasos 16 well to test the west-side of the Guaduas Oil Field
structure at an estimated gross cost of $5.5 million ($3.0 million net
to the Company).

34
35

In summary, in 2001 the Company plans to complete the construction of the
pipeline and production facilities for the Guaduas Oil Field, drill four
development wells and one injector well on the Guaduas Oil Field and drill three
exploration wells on its Colombian properties. The estimated gross costs of this
development and exploration strategy in 2001 are $67.5 million, the Company's
share of which is approximately $45.8 million.

The Company's ability to fully implement our exploration and development
strategy is subject to 1) securing financing for its share of the costs, 2)
timely receiving required environmental permits, 3) contracting the required oil
and gas services and equipment and 4) completing the Guaduas--La Dorada pipeline
and commencing pipeline utilitization.

CAPITAL AVAILABILITY AND LIQUIDITY

The Company's sources of cash in 2001 will come from cash and cash
equivalents of $12.1 million, availability of $10 million under the Stillwater
National Bank loan and operating cash flows from production in the Guaduas Oil
Field. Production from the Guaduas Oil Field has a very short history and is
subject to all the normal risks of oil and gas operations. Further, to achieve
full production rates, the Guaduas--La Dorada pipeline and related production
facilities will need to be completed and in operation by mid-2001.

The Company's cash requirements in 2001 include commitments under existing
oil and gas agreements of approximately $17.9 million (not including a potential
obligation of $2.1 million on the Tapir association contract), the November 2001
interest payment of $6.9 million on the $110 million senior notes and general
and administrative expenses.

The Company's ability to meet its existing commitments and operating needs
is highly dependent on production from the Guaduas Oil Field. The Company's
dependence on production is such that (i) if it is interrupted for an extended
period of time, (ii) if the prices received or the costs incurred fail to meet
expectations or (iii) if the pipeline and related production facilities are not
completed and in operation as planned, then the Company will likely not be able
to meet 2001 cash requirements. In that case, the Company will have to seek
additional financing to meet its existing commitments and operating needs in
2001.

Failure to obtain additional financing would raise substantial doubt about
the Company's ability to continue as a going concern. The financial statements
do not include any adjustments that might result from the outcome of this
uncertainty.

Under the terms of the Company's $110 million senior notes, it is permitted
to incur general indebtedness that can be senior to its senior notes not
exceeding the greater of (i) $25 million, or (ii) the sum of 100% of its cash
and cash equivalents, plus 100% of its receivables from Ecopetrol, and plus 30%
of its discounted future net revenues from proved oil and gas reserves prepared
in accordance with the rules of the United States Securities and Exchange
Commission. As of December 31, 2000, the permitted amount was approximately
$130.3 million. The Company is also allowed to borrow an additional $10 million
for project financing, e.g., pipeline and production facilities.

Any additional financing obtained by the Company to execute its business
plans may result in a dilution of current stakeholder interests. Seven Seas
cannot be certain that additional sources of financing will be available when
needed or will be available on acceptable terms. The Company has suffered
recurring losses from operations, has an accumulated deficit, has not generated
positive cash flow from operations, has significant unproved property balances,
is nearing the end of the exploration phase of its association contracts, is
highly dependant on the actions of Ecopetrol, and will likely require additional
capital to fully execute its business plans.

RISK FACTORS

Seven Seas is subject to several categories of risk associated with its
development stage activities. Oil and gas exploration and development is a
speculative business and involves a high degree of risk. Among the factors that
have a direct bearing on Seven Seas' prospects are uncertainties inherent in
estimating oil and gas reserves and future hydrocarbon production and cash
flows, particularly with respect to wells that have not been fully tested and
with wells having limited production testing histories; access to additional
capital; changes in the price of oil and natural gas, services and equipment;
the limited exploration of the association contracts; the status of existing and
future contractual relationships with Ecopetrol; regulation in Colombia; lack of
significant income producing property; foreign currency fluctuation risks; Seven
Seas' substantial indebtedness, the presence of competitors with greater
financial resources and capacity; and difficulties and risks associated with
operating in Colombia.

2. BACKGROUND:

On June 29, 1995 the Supreme Court of British Columbia approved the May 5,
1995 amalgamation of Seven Seas and Rusty Lake Resources Ltd. Stockholders of
Rusty Lake Resources Ltd. were issued one common share in Seven Seas, the new
company after the amalgamation, for each 35 common shares held in Rusty Lake
Resources Ltd. Additional shares of Seven Seas were issued in settlement of
certain indebtedness of Rusty Lake Resources Ltd. This transaction has been
reflected as an acquisition by Seven Seas using the purchase method of
accounting, whereby the assets acquired and liabilities assumed were recorded at
the fair value and Rusty Lake Resources Ltd. has been prospectively reflected in
the Company's financial statements since June 29, 1995.

35
36

On July 26, 1996 the Company acquired 100 percent of the outstanding stock
which represented 100 percent of the voting shares held in GHK Company Colombia
and Esmeralda LLC. Additionally, on the same date, the Company acquired 62.963
percent of the outstanding shares and voting stock in Cimarrona LLC. This
transaction has been reflected as an acquisition by Seven Seas using the
purchase method of accounting, whereby the assets acquired and liabilities
assumed were fair valued and the operations of the acquired entities have been
reflected in the Company's financial statements since July 26, 1996. As
consideration for the increased interest from these acquisitions, Seven Seas
issued to the stockholders in GHK Company Colombia, Esmeralda LLC and Cimarrona
LLC a combination of preferred shares and special warrants which were
exchangeable into a total of 16,777,143 common shares upon the earlier of the
approval of a prospectus qualifying the exchange, or one year from the closing
of the transaction. Of the 16,777,143 preferred shares and special warrants,
5,002,972 preferred shares were issued for all of the common shares in GHK
Company Colombia, 4,469,028 special warrants were issued for all of the common
shares in Esmeralda LLC, and 7,305,143 special warrants were issued for 62.963
percent of the common shares in Cimarrona LLC. The remaining 37.037 percent
interest in Cimarrona LLC represents a minority interest which is reflected as
such on the balance sheet. The 16,777,143 preferred shares and special warrants
were recorded based on the closing stock price of Seven Seas on July 26, 1996 at
$9.125 per share totaling $153.1 million. Collectively, the acquisition of these
three companies resulted in the purchase of an additional 36.7 percent
participating interest in the Dindal and Rio Seco association contracts in which
the Company previously held a 15 percent participating interest. All three
entities were oil and gas exploration companies whose only material asset was
the participating interest they held in the Dindal and Rio Seco association
contracts in Colombia. Net assets acquired include $217.1 million assigned to
oil and gas properties and other nominal net working capital, less amounts
attributable to the minority interest in Cimarrona LLC. Because of the
differences in tax basis and the financial statement valuation of such acquired
oil and gas properties, $64.0 million of deferred Colombian and U.S. income
taxes was also recorded in this acquisition (see Note 6) and is included in the
amount assigned to oil and gas properties. Income and expenditures incurred by
these three entities after July 26, 1996 are included in the statements of
operations and accumulated deficit for the years ended December 31, 1998, 1997
and 1996.

Of the 16,777,143 preferred shares and special warrants issued, 11,744,000
were held subject to an escrow agreement, whereby one third of the securities
are released each year for three years. The securities could have been released
earlier based upon a valuation of the Seven Seas interests in the Dindal and Rio
Seco association contracts. As of July 26, 1999, all of the common shares have
been released from escrow pursuant to the escrow agreement.

On February 7, 1997 approvals were granted by the Ontario Securities
Commission, British Columbia Securities Commission and the Alberta Securities
Commission for the prospectus filed to qualify 11,774,171 special warrants and
5,002,972 preferred shares which were automatically converted to common shares.
These shares were issued in connection with the acquisition of a 36.7 percent
participating interest in the Dindal and Rio Seco association contracts in
Colombia by the Company on July 26, 1996, as described above.

On March 5, 1997 the Company acquired 100 percent of the outstanding voting
stock held in Petrolinson, S.A. The terms of the transaction were agreed to in a
letter of intent dated November 22, 1996. The principal asset owned by
Petrolinson, S.A. is a six percent participating interest in the Dindal and Rio
Seco association contracts. As consideration for the six percent participating
interest in these association contracts, Seven Seas issued to the sole
shareholder in Petrolinson, S.A. 1,000,000 common shares of Seven Seas Petroleum
Inc. The common shares issued to the sole shareholder of Petrolinson, S.A. were
subject to an escrow agreement, the terms of which provided for a 120 day escrow
of shares commencing from March 5, 1997 with an option by the Company to extend
the escrow period for an additional 30 days. The 1,000,000 common shares issued
to the sole shareholder of Petrolinson, S.A. were released from escrow on July
3, 1997, in accordance with the escrow agreement as described above. This six
percent interest will be carried through exploration by the other 94 percent
participating interest parties. This transaction was reflected in 1997 as an
acquisition by Seven Seas using the purchase method of accounting, whereby the
assets acquired and liabilities assumed were fair valued and the acquired
operations have been reflected in the Company's financial statements since March
5, 1997. The 1,000,000 common shares were recorded at a price of $18.55, based
on the weighted average closing stock price of Seven Seas for the period
beginning 30 days prior to and ending 30 days subsequent to the date the letter
of intent was signed, November 22, 1996, which represented a transaction cost of
$18.6 million. Net assets acquired include $25.0 million assigned to oil and gas
properties (most of which is subject to future evaluation based on further
appraisal drilling) and other nominal net working capital. Because of the
differences in tax basis and the financial statement valuation of such acquired
oil and gas properties, $6.5 million of deferred Colombian income tax was also
recorded in this acquisition (see Notes 3 and 6) and is included in the amount
assigned to oil and gas properties.

3. SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES:

The Company follows accounting principles generally accepted in the United
States. A summary of the Company's significant policies is set out below:

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37
USE OF ESTIMATES

The preparation of financial statements in conformity with generally
accepted accounting principles requires the Company to make estimates and
assumptions that affect the reported amounts of assets and liabilities, revenues
and expenses. Actual results could differ from the estimates and assumptions
used. Significant estimates include depreciation, depletion and amortization of
proved oil and gas reserves. Oil and natural gas reserve estimates, which are
the basis for depletion and the ceiling test, are inherently imprecise and
expected to change as future information becomes available.

CONSOLIDATION

The consolidated financial statements include the accounts of the Company
and its wholly owned subsidiaries, after eliminating all material intercompany
accounts and transactions.

FAIR VALUE OF FINANCIAL INSTRUMENTS

The recorded amounts of cash and cash equivalents, accounts receivable and
accounts payable approximate fair value because of the short-term maturity of
those investments. The fair value of the Company's 12 1/2% $110 million Senior
Notes was $44.6 million at December 31, 2000.

INVESTMENTS

The Company has adopted Statement of Financial Accounting Standards No. 115
("SFAS 115"), "Accounting for Certain Investments in Debt and Equity
Securities." SFAS 115 requires that all investments in debt securities and
certain investments in equity securities be reported at fair value except for
those investments which management has the intent and the ability to hold to
maturity (see Note 5). Investments which are held-for-sale are classified based
on the stated maturity and management's intent to sell the securities. Changes
in fair value are reported as a separate component of stockholders' equity, but
were immaterial for all periods presented herein.

ACCOUNTS RECEIVABLE

Accounts receivable included the following at December 31, 2000 and 1999 (In
thousands):

DECEMBER 31,
-----------------------
2000 1999
---------- ----------

Crude oil sales ............................. $ 4,476 $ 4,445
Joint interest billing ...................... 2,808 5,067
Other ....................................... 13 309
---------- ----------
Total accounts receivable ......... $ 7,297 $ 9,821
========== ==========

INVENTORY

Inventories consist primarily of goods used in the Company's operations and
are stated at the lower of average cost or market value.

OIL AND GAS INTERESTS

The Company follows the full-cost method of accounting for oil and natural
gas properties. Under this method, all costs incurred in the acquisition,
exploration and development, including unproductive wells, are capitalized in
separate cost centers for each country. Such capitalized costs include
association contract and concession acquisition, geological, geophysical and
other exploration work, drilling, completing and equipping oil and gas wells,
constructing production facilities and pipelines, and other related costs. We
capitalized general and administrative costs of $0.2 million, $0.3 million, and
$0.3 million in 2000, 1999 and 1998, respectively. The Company capitalized
interest of $13.2 million, $13.8 million and $9.8 million in 2000, 1999 and
1998, respectively.

The capitalized costs of oil and gas properties in each cost center are
amortized on composite units of production method based on future gross revenues
from proved reserves. Sales or other dispositions of oil and gas properties are
normally accounted for as adjustments of capitalized costs. Gain or loss is not
recognized in income unless a significant portion of a cost center's reserves is
involved. Capitalized costs associated with the acquisition and evaluation of
unproved properties are excluded from amortization until it is determined
whether proved reserves can be assigned to such properties or until the value of
the properties is impaired. If the net capitalized costs of oil and gas
properties in a cost center exceed an amount equal to the sum of the present
value of estimated future net revenues from proved oil and gas reserves in the
cost center and the lower of cost or fair value of properties not being
amortized, both adjusted for income tax effects, such excess is charged to
expense. There was not a write-down in 2000 or 1999. At December 31, 1998, the
Company recognized a non-cash write-down of oil and gas properties in the amount
of $129.8 million pre-tax or $84.4 million after tax pursuant to this ceiling
limitation. The write-down was primarily the result of the decline in crude oil
prices and the impairment of unevaluated properties due primarily to the failure
of four non-commercial exploratory wells.

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38

The Company began to record a provision for depletion of its oil and gas
properties in the fourth quarter of 1999. The Company recorded depletion of $0.7
million and $0.8 million in 2000 and 1999, respectively. Depletion per barrel
was $3.86 and $3.83 in 2000 and 1999, respectively.

Substantially all the Company's exploration and production activities are
conducted jointly with others and the accounts reflect only the Company's
proportionate interest in such activities.

REVENUE RECOGNITION

The Company records as revenue only that portion of production sold and
allocable to its ownership interest in the related property.

FOREIGN CURRENCY TRANSLATION

The Company's foreign operations are a direct and integral extension of the
parent company's operations and the majority of all costs associated with
foreign operations are paid in U.S. dollars as opposed to the local currency of
the operations; therefore, the reporting and functional currency is the U.S.
dollar. Gains and losses from foreign currency transactions are recognized in
current net income. Monetary items are translated using the exchange rate in
effect at the balance sheet date; non-monetary items are translated at
historical exchange rates. Revenues and expenses are translated at the average
rates in effect on the dates they occur. No material translation gains or losses
were incurred during the periods presented.

INCOME TAXES

The Company follows the asset/liability method of accounting for income
taxes. Under this method, deferred tax assets and liabilities are recognized for
the future tax consequences of (i) temporary differences between the tax bases
of assets and liabilities and their reported amounts in the financial statements
and (ii) operating loss and tax credit carryforwards for tax purposes. Deferred
tax assets are reduced by a valuation allowance when, based upon management's
estimates, it is more likely than not that a portion of the deferred tax assets
will not be realized in a future period.

FIXED ASSETS

Fixed assets are recorded at cost. Depreciation is provided on a
straight-line basis over eighteen months to five years.

EARNINGS PER SHARE

The Company has implemented Statement of Financial Accounting Standards No.
128 ("SFAS 128"), "Earnings per Share." SFAS 128 establishes standards for
computing and presenting earnings per share. Options to purchase 4,188,848
common shares at a weighted average option exercise price of $7.82 per common
share were outstanding at December 31, 2000.

CONTINGENCIES

Liabilities and other contingencies are recognized upon determination of an
exposure, which when analyzed indicates that it is both probable that an asset
has been impaired or that a liability has been incurred and that the amount of
such loss is reasonably estimatable. Costs to remedy or defend against such
contingencies are charged to expense as they are incurred.

NEW ACCOUNTING PRONOUNCEMENTS

In June 1998, the Financial Accounting Standards Board issued Statement of
Financial Accounting Standards ("SFAS") No. 133, "Accounting for Derivative
Instruments and Hedging Activities". The Statement, as amended by SFAS 137 and
SFAS 138, establishes accounting and reporting standards requiring that every
derivative instrument, including certain derivative instruments embedded in
other contracts, be recorded in the balance sheet as either an asset or
liability measured at its fair value. The Statement requires that changes in the
derivative's fair value be recognized currently in earnings unless specific
hedge accounting criteria are met. Special accounting for qualifying hedges
allows a derivative's gains and losses to offset related results on the hedged
item in the income statement, and requires that a company must formally
document, designate, and assess the effectiveness of transactions that receive
hedge accounting. The Company will adopt this Statement as of January 1, 2001
and expects that SFAS 133 will not have a material impact on the Company's
disclosure and reporting.

In the first quarter of 2000, FASB issued Interpretation No. 44 "Accounting
for Certain Transactions involving Stock Compensation - an interpretation of APB
No. 25 ("the Interpretation") which clarifies the application of APB 25 for
certain issues associated with accounting for the issuance or subsequent
modification of stock compensation and is effective July 1, 2000. For

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39

certain modifications, including stock option repricings made subsequent to
December 15, 1998, the Interpretation requires that variable plan accounting be
applied to those modified awards prospectively from July 1, 2000. In January and
November 1999, the Company repriced certain employee stock options for 706,000
shares of stock at a weighted average exercise price of $14.47 to a new exercise
price of $9.00 through the cancellation of existing options and issuance of new
options at or above current market prices. Upon adoption of this statement, the
exercise price of the repriced options exceeded the Company's stock price
resulting in no compensation expense to be recognized over future vesting.
Subsequent to the adoption of the Interpretation, the Company may be required to
record the effects of the changes in its stock price and the corresponding
change in intrinsic value of the repriced options in its results of operations
as compensation expense.

4. CASH AND CASH EQUIVALENTS:

The Company considers highly liquid investments with a maturity of three
months or less as cash equivalents. The following table sets forth the Company's
cash and cash equivalents (in thousands):

DECEMBER 31,
-----------------------
2000 1999
---------- ----------

Cash ............................................. $ 4,472 $ 1,371
Cash equivalents ................................. 7,656 21,076
---------- ----------
Total cash and cash equivalents ........ $ 12,128 $ 22,447
========== ==========

5. INVESTMENTS AND RESTRICTED INVESTMENTS:

At December 31, 2000, all the Company's investments were classified as
held-to-maturity. The securities have a maturity date within one year, are
classified as short-term investments as part of current assets, and are stated
at amortized cost as of December 31, 2000. The calculation of gross unrealized
loss for the year ended December 31, 2000 was as follows (In thousands):

AMORTIZED UNREALIZED
FAIR VALUE COST LOSS
---------- ---------- ----------

RESTRICTED SHORT-TERM INVESTMENTS
U.S. Treasury Strip, face value of $6,875,000, due
May 15, 2001 ............................................ 6,732 6,734 (2)
---------- ---------- ----------
Total Short-term restricted
investments ...................................... $ 6,732 $ 6,734 $ (2)
========== ========== ==========

Net unrealized losses on held-to-maturity securities have not been
recognized in the accompanying consolidated financial statements. The restricted
investments were pledged or placed in escrow for the first three years of
interest payments on the $110 million 12 1/2% Senior Notes (see Note 7).

6. INCOME TAXES:

The geographical sources of income (loss) before income taxes and minority
interest were as follows (In thousands):

YEAR ENDED DECEMBER 31,
--------------------------------------
2000 1999 1998
---------- ---------- ----------

United States ......................................... $ 95 $ 727 $ 3,348
Foreign ............................................... (5,962) (8,047) (140,043)
---------- ---------- ----------
Loss before income taxes and minority
interest .................................. $ (5,867) $ (7,320) $ (136,695)
========== ========== ==========

Deferred U.S. and Colombian income taxes have been provided for the book-tax
basis differences related to the Colombian acquisitions discussed in Note 2.
These foreign subsidiaries' cumulative undistributed earnings are considered to
be indefinitely reinvested outside of Canada and, accordingly, no Canadian
deferred income taxes have been provided thereon.

The Company's net deferred income tax liabilities consist of the following
(In thousands):

DECEMBER 31,
--------------------------------------
2000 1999 1998
---------- ---------- ----------

Deferred tax liabilities ............... $ (24,732) $ (25,033) $ (25,033)
Deferred tax asset ..................... 24,595 14,927 8,953
Valuation allowance .................... (24,566) (14,688) (8,652)
---------- ---------- ----------
Total deferred tax ........... $ (24,703) $ (24,794) $ (24,732)
========== ========== ==========

The Company's provision for income taxes differs from the amount computed by
applying statutory rates, which are 45% in Canada and 35% in the United States
and Colombia, due principally to the valuation allowance recorded against its
deferred tax asset account relating primarily to net operating tax loss
carryforwards. In 1998, the Company released the valuation allowance
attributable to US net operating loss carryforwards, resulting in a deferred tax
benefit of $0.3 million, net of current US tax expense of $8,700 and a reduction
in deferred tax liabilities of $45.4 million was recognized relating to the
Company's write-down of oil and gas properties.

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40

Temporary differences included in the deferred tax liabilities relate
primarily to the excess of book over tax basis on acquired oil and gas
properties in Colombia. Portions of the Company's Colombia assets are owned
through a U.S. subsidiary. No U.S. deferred tax liabilities related to the
excess of book over tax basis on acquired Colombian properties have been
recorded. The potential for incremental U.S. income tax associated with the
excess of book over tax basis depends on the ability to generate sufficient
taxable income of the appropriate character in the future.

As of December 31, 2000, the Company's subsidiaries had net operating loss
carryforwards in various foreign jurisdictions (primarily Canada) of
approximately $46.4 million. In addition, the Company had at December 31, 2000,
$7.4 million of U.S. tax net operating loss carryforwards. The Canadian loss
carryforwards will expire beginning in 2002 if not utilized to reduce Canadian
income taxes. In addition, the US tax net operating loss carryforwards expire in
varying amounts over the years 2011-2020. A valuation allowance has been
provided for all of the Canadian and U.S. deferred tax assets relating to the
remaining loss carryforwards because their future realization is not currently
deemed more likely than not by management.

The continuation of Seven Seas-Yukon as Seven Seas-Cayman, mentioned in
Note 15, will result in Seven Seas ceasing to be resident in Canada for the
purposes of the Canadian Tax Act. As a result, Seven Seas-Yukon's current
taxation year is deemed to have ended immediately before the continuation. In
addition, Seven Seas-Yukon is deemed to have disposed of all of its property
immediately before the continuation for proceeds equal to the fair market value
of such property. Accordingly, Seven Seas is subject to Canadian federal income
tax on any income and net taxable capital gains that result from such deemed
disposition. Seven Seas is also subject to an additional tax of 25% of the
amount by which the fair market value of Seven Seas' assets, net of certain
liabilities, exceeds the paid-up capital of the outstanding Seven Seas-Yukon
shares immediately before the continuation.

Management of Seven Seas believes that, based on the preliminary appraisal
of the value of its assets, the current tax cost of its assets, the amount of
its existing liabilities and the paid-up capital of its shares outstanding as of
December 31, 2000, no Canadian federal income taxes is payable as a result of
the continuation.

The continuation of a Canadian corporation to a jurisdiction outside Canada
is a taxable event for Canadian purposes. However, any conclusion about whether
there will be any tax due or the amount thereof will depend on the facts and its
not a legal determination. Several factual determinations influence this,
including 1) the value of Seven Seas' assets, 2) the tax attributes of its
assets, 3) the amount of its liabilities, and 4) the "paid-up capital" of its
outstanding shares.

7. DEBT AND LONG-TERM OBLIGATIONS:

Exchangeable Notes. In August 1997, the Company issued $25 million of
Exchangeable Notes in a private transaction with institutional and accredited
investors. The Exchangeable Notes accrued interest at a rate of 6% per annum and
were payable on December 31 and June 30 in each year, commencing December 31,
1997. The Exchangeable Notes were scheduled to mature on August 7, 2003.

The Exchangeable Notes were exchanged for a like principal amount of
Convertible Debentures on August 5, 1998. The Convertible Debentures were
converted on August 6, 1998 into units consisting of a total of 2,173,901 common
shares and warrants exercisable for 1,086,957 common shares. The Company
received proceeds of $0.3 million from the exercise of 18,913 warrants. On
February 5, 1999, the remaining warrants expired unexercised.

Senior Notes. The Company issued $110 million aggregate principal amount of
12 1/2% Senior Notes due 2005 (the "Senior Notes") in a private transaction on
May 7, 1998 that was not subject to registration requirements of the Securities
Act of 1933. The Senior Notes mature on May 15, 2005. Interest on the Senior
Notes is payable semi-annually in arrears on May 15 and November 15. The Senior
Notes place restrictions on, among other things, net working capital balances,
dividend distributions, changes in control, and asset sales and indebtedness.

The Senior Notes represent senior obligations of the Company, ranking pari
passu in right and priority of payment with all existing and future senior
indebtedness and senior in right and priority of payment to all indebtedness
that is expressly subordinated to the Senior Notes.

In accordance with the terms of the Senior Notes, the Company purchased
$13.5 million in U.S. Government Securities from the proceeds of the Senior
Notes and deposited such securities in a segregated account in an amount that
will be sufficient to provide for payment of the first two scheduled interest
payments (see Note 5). Additionally, the Company purchased and pledged to the
Bank of Nova Scotia Trust Company New York, the Trustee, as security for the
benefit of the holders of the Senior Notes, U.S. Government Securities of $25
million that will be sufficient to provide payment of the four scheduled
interest payments on the Notes from November 15, 1999 through May 15, 2001. The
Company does not have funds in escrow for interest payments commencing with the
November 15, 2001 payment. Such securities are classified as restricted
short-term investments as of December 31, 2000. (see Note 5).

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41
Stillwater National Bank Loan. In December 2000, the Company entered into a
$10 million loan agreement with Stillwater National Bank and Trust Company, N.A.
On March 30, 2001, the loan's maturity date was extended from December 31, 2001
to April 1, 2002. The Stillwater National Bank loan is secured by all of the
stock of the operating subsidiaries of Seven Seas and is guaranteed by Robert A.
Hefner III, chairman and chief executive officer of Seven Seas. Mr. Hefner
received remuneration of $62,500 for his guarantee. The loan bears interest at
an annual rate of the Prime Rate plus .75%, and interest is payable monthly
until the loan is due in full on April 1, 2002. Seven Seas intends to use these
funds for working capital and plans to replace, without penalty, this
non-convertible loan with the proceeds from a larger financing planned for 2001.
As of the issuance date of these financial statements, the Company had drawn
$3.0 million on this loan.

8. EQUITY:

On March 15, 1996, a brokered private placement was carried out in Canada in
which the Company issued to a third party financial brokerage institution
2,000,000 special warrants at $2.75 per warrant for net offering proceeds after
commissions and expenses of $5.1 million. Each special warrant was convertible
into one unit. Each unit consisted of one share of common stock and a one-half
common share purchase warrant at $3.50 per full share. The warrants were
convertible at the earlier of (a) one year from date of issuance or (b) the date
an approval is issued for a prospectus qualifying the conversion in the
appropriate jurisdictions. On March 14, 1997, the 1,000,000 common share
purchase warrants were exercised and converted to common shares for net proceeds
of $3.5 million.

On October 16, 1996, another brokered private placement was carried out in
Canada. Seven Seas issued to a third party financial brokerage institution
500,000 special warrants at $15.00 per warrant for a net offering after
commissions and expenses of $7.0 million. Each special warrant was convertible
into one Unit (see Note 7). Each Unit consisted of one share of common stock and
a one-half common share purchase warrant at $18.50 per full share. The warrants
were convertible at the earlier of (a) one year from date of issuance or (b) the
date an approval is issued for a prospectus qualifying the conversion in the
appropriate jurisdictions. The 250,000 common share purchase warrants were not
exercised and expired October 16, 1997.

An approval for qualification of the conversion of the 2,000,000 and 500,000
special warrants issued in the brokered private placements on March 15 and
October 16, 1996, respectively, was received on February 7, 1997 by the Ontario,
Alberta, and British Columbia Securities Commissions. All special warrants were
exercised and have been converted to common shares.

The proceeds of the brokered private placements on March 15 and October 16,
1996 were used for drilling, seismic and production facilities related to the
Company's participation in the Dindal and Rio Seco association contracts and for
further exploration activities.

9. STOCK BASED COMPENSATION PLANS:

Officers, directors and certain employees have been granted stock options
under the Company's Amended 1996 Stock Option Plan and the Amended and Restated
1997 Stock Option Plan (collectively referred to as "the Plans"). Pursuant to
the Plans, 6,000,000 shares were authorized for issuance, of which 4,188,848
were outstanding as of December 31, 2000. The Compensation Committee may
establish the term of each incentive stock option granted under the Amended 1996
Stock Option Plan, but if not so established, the term of each option will be
five years from the date it is granted, but in no event shall the term of any
option exceed ten years. Options granted under the Amended and Restated 1997
Stock Option Plan have been granted with either no vesting requirement or
vesting cumulatively on the anniversary of the grant date over a period of two
to five years and expire ten years from the date of grant. Option agreements
between the Company and optionees under the 1997 Stock Option Plan may include
stock appreciation rights; however, no such rights are currently outstanding.
Under the Plans, the option price equals not less than the average of the high
and low trading price of the Company's stock on the date of grant.

The Compensation Committee of the Board of Directors is responsible for
administering the Plans, determining the terms upon which options may be
granted, prescribing, amending and rescinding such interpretations and
determinations and granting options to employees, directors, and officers.

The following table presents a summary of stock option transactions for the
three years ended December 31, 2000:

WEIGHTED AVERAGE
COMMON OPTION PRICE
SHARES PER SHARE
---------------- ----------------

December 31, 1997 ...... 3,878,500 $ 13.51
Granted ................. 820,500 13.97
Exercised ............... (514,000) 8.02
Revoked ................. (703,833) 17.13
---------------- ----------------
December 31, 1998 ...... 3,481,167 13.69
Granted ................. 1,553,434 6.06
Revoked ................. (1,590,000) 14.03
---------------- ----------------
December 31, 1999 ...... 3,444,601 10.10
Granted ................. 1,025,581 2.44
Exercised ............... (3,000) 0.75
Revoked ................. (278,334) 16.29
---------------- ----------------
December 31, 2000 ...... 4,188,848 $ 7.82
================ ================

Exercisable stock options amounted to 3,399,850, 2,091,935, and 1,718,829 at
December 31, 2000, 1999, and 1998, respectively. The weighted average fair value
of options granted during 2000, 1999, and 1998 were $1.58, $3.16 and $8.77,
respectively. The following table summarizes stock options outstanding and
exercisable at December 31, 2000:

OUTSTANDING EXERCISABLE
------------------------------------------------ -------------------------------
WEIGHTED WEIGHTED
EXERCISE PRICE AVERAGE AVERAGE AVERAGE
RANGE SHARES LIFE EXERCISE PRICE SHARES EXERCISE PRICE
- ------------------------------ -------------- -------------- -------------- -------------- --------------

$1.06 - 1.94 ................. 345,787 5.5 $ 1.44 245,787 $ 1.49
2.00 - 2.94 ................. 377,564 5.2 2.69 295,564 2.67
3.00 - 3.94 ................. 719,664 8.4 3.02 284,331 3.04
4.22 - 4.81 ................. 375,000 8.4 4.26 375,000 4.26
6.16 - 7.13 ................. 10,000 4.3 6.64 10,000 6.64
8.06 - 8.63 ................. 175,000 4.8 8.46 158,334 8.45
9.00 ........................ 1,008,500 7.4 9.00 853,501 9.00
10.70 - 10.90 ............... 629,000 6.5 10.70 629,000 10.70
14.09 ....................... 18,000 7.6 14.09 18,000 14.09
18.55 - 18.75 ............... 530,333 5.7 18.59 530,333 18.59
-------------- --------------
4,188,848 3,399,850
============== ==============

As part of the arrangements surrounding the resignations of four former
officers, the exercise period of the options granted during their employment was
extended from ninety days to eighteen months. This action gave rise to a new
measurement date and the Company was required to record compensation expense of
$2.1 million during 1997, representing the market value of the common shares on
the new measurement date less the exercise price of the options granted. Only
the exercisable options granted to the former Chairman, former President, former
Chief Financial Officer, and former Vice President of Exploration were
considered in the computation.

During 1999, the Company re-priced options granted to certain employees by
canceling existing options with exercise prices at or above market prices on the
date of grant.

In accordance with the provisions of Statement of Financial Accounting
Standards No. 123, "Accounting for Stock-Based Compensation" ("SFAS 123"), the
Company applies APB Opinion 25 in accounting for its stock option plan, and
accordingly does not recognize compensation cost at fair value as it relates to
SFAS 123. If the Company had elected to recognize compensation cost based on the
fair value of the options granted at the grant date as prescribed by SFAS 123,
net loss and net loss per share would have increased to the proforma amounts
shown below:

DECEMBER 31,
--------------------------------------
2000 1999 1998
---------- ---------- ----------

Pro Forma Net Loss (In thousands) ...... $ (7,524) $ (11,695) $ (97,393)
Pro Forma Net Loss Per Share ........... $ (0.20) $ (0.31) $ (2.69)

The effects of applying SFAS 123 in this proforma are not indicative of
future amounts.

The fair value of each option grant is estimated on the date of grant using
the Black-Scholes option pricing model with the following assumptions used for
grants during the year ended December 31, 2000: weighted average risk free
interest rate of 6.08 percent; no dividend yield; volatility of .8258; and
expected life of ten years. The Company granted options prior to public trading
on the Canadian Dealer Network on June 30, 1995. Consequently, the underlying
common shares had no historic volatility prior to June 30, 1995. The fair values
of the options granted prior to June 30, 1995 were based on the difference
between the present value of the exercise price of the option and the estimated
fair value price of the common shares.

10. DEFINED CONTRIBUTION PLAN:

The Company offers a qualified defined contribution plan, which is a
combined salary reduction plan under Section 401(k) of the Internal Revenue
Code. Participants can invest from 1% to 15% of earnings, up to the maximum
allowed by law, among several investment alternatives, including a Company stock
fund. The Company does not match funds invested in the Plan and recognized no
expense in 2000, 1999, or 1998, respectively due to contributions to the Plan.

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11. OPERATIONS BY GEOGRAPHIC AREA:

The Company has one operating and reporting segment. Information about the
Company's operations for 2000, 1999 and 1998 by geographic area is shown below
(In thousands):

OTHER
UNITED FOREIGN
CANADA STATES COLOMBIA AREAS TOTAL
--------- --------- --------- --------- ---------

Year ended December 31, 2000
Revenues .......................... $ 1,696 $ 12 $ 4,726 $ -- $ 6,434
Operating Income (Loss) ........... (2,633) 95 (3,314) (15) (5,867)
Capital Expenditures .............. -- 151 6,540 -- 6,691
Identifiable Assets ............... 56,147 750 197,116 63 254,076
Depletion, depreciation and
amortization ................... 607 289 833 -- 1,729
Year ended December 31, 1999
Revenues .......................... $ 2,938 $ 12 $ 2,363 $ -- $ 5,313
Operating Income (Loss) ........... (979) 727 (6,378) (690) (7,320)
Capital Expenditures .............. -- 74 12,521 250 12,845
Identifiable Assets ............... 69,515 1,082 190,404 81 261,082
Depletion, depreciation and
amortization ................... 607 332 886 -- 1,825
Year ended December 31, 1998
Revenues .......................... $ 3,626 $ 12 $ 159 $ -- $ 3,797
Operating Income (Loss) ........... (2,714) 3,348 (137,761) 432 (136,695)
Capital Expenditures .............. -- 997 43,568 115 44,680
Identifiable Assets ............... 91,067 1,430 186,902 501 279,900
Depreciation and amortization ..... 485 140 49 -- 674

12. COMMITMENTS AND CONTINGENCIES:

The Company leases property and equipment under various operating leases.
Aggregate minimum lease payments under existing contracts as of December 31,
2000, are as follows: $0.3 million for 2001; $0.3 million for 2002; and $0.1
million for 2003 and none thereafter. Rental expense amounted to $0.3 million in
2000; $0.3 million in 1999; $0.2 million in 1998.

The Company has certain non-discretionary related commitments under existing oil
and gas agreements. Management estimates future expenditures for such
commitments to be approximately $17.9 million in 2001 (not including a potential
obligation on the Tapir association contract), $0.5 million in 2002 and none
thereafter.

ENVIRONMENTAL PENALTIES

On June 8, 1998, the Ministry of Environment required the Company's
subsidiary, GHK Company Colombia, to perform some remedial work on the El
Segundo 6-E location and access road. GHK Company Colombia performed the work,
and thereafter reported to the Ministry of Environment that all the work had
duly been completed. In various site visits, ministry officials have confirmed
that the alleged violations have been properly remedied. On July 8, 1999, GHK
Company Colombia filed all the documentation, confirming total compliance with
the requirements.

In March 2000, the Company paid a fine of approximately $223,000 to the
Ministry of Environment in connection with a resolution issued against GHK
Company Colombia by the Ministry of Environment in which it declared GHK Company
Colombia to be in violation of a 1997 decree in connection with the construction
of the El Segundo 7-E well location. The Company has filed an appeal for a
reversal of the resolution and believes that we have corrected the environmental
violations claimed by the Ministry of Environment. However, the appeal process
can take up to two years. The El Segundo 7-E location has been restored and the
Company currently does not have drilling activities planned at this location.

HEIRS OF NICOLAS BELTRAN FRANCO

Two of the Company's subsidiaries, Petrolinson, S.A. and GHK Company
Colombia, along with the former owner of Petrolinson, S.A., Norman Rowlinson and
the heirs of Howard Thomas Corrigan, are defendants in a lawsuit that was filed
in Santa Fe de Bogota, Colombia in 1998. The plaintiffs, who are the heirs of
Nicolas Beltran Franco, have two claims. First, they claim that a de facto
company existed between Nicolas Beltran Franco and the defendants concerning the
Dindal and Rio Seco association contract areas. Second, they claim that before
the Dindal and Rio Seco association contracts were executed, the de facto
company conducted exploration works in the Dindal and Rio Seco association
contract areas. The plaintiffs claim they have the right to participate in
income earned from the Dindal and Rio Seco association contract areas. None of
the plaintiffs are party to the association contracts. However, they are seeking
50% of the income generated by the de facto company they claim existed. It is
not clear what percentage of the Dindal and Rio Seco association contract areas
are covered by the plaintiffs' claims. The Company's Colombian counsel,
Raisbeck, Lara, Rodriguez and Rueda, members of the law firm of Baker and
McKenzie, believe that if this claim is litigated the chances of the plaintiffs
succeeding are remote.

SURFACE LOCATION

A lawsuit was filed by the landowner of the El Segundo 1 surface location to
cancel the Company's surface lease. The Company responded to this claim on
November 4, 1999, and has vigorously defended this claim. Examinations regarding
the claim were held in

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44

September 2000, and the probatory stage of the matter was closed on March 21,
2001. The Company's Colombian legal counsel, Gamba, Barrera, Arriaga y
Asociados, has advised the Company that, on the basis of the claims asserted, it
is unlikely that it will lose the lawsuit.

NOTEHOLDER CLAIM

FORMER MANAGEMENT

Seven Seas and two of its officers and directors, Robert A. Hefner, III and
Larry Ray, and one of its former directors, Breene M. Kerr, have been sued by
four former Seven Seas officers and directors in DeCort, et al. v. Seven Seas
Petroleum Inc., et al., Cause No. 2000-50498, District Court of Harris County,
Texas, 133rd Judicial District. Plaintiffs allege that Seven Seas failed to
obtain extensions of time in which the plaintiffs could exercise certain stock
options granted to them, and that all defendants induced them to enter into
separation agreements with Seven Seas that they would have not entered into but
for Seven Seas' agreement to obtain an extension of time for plaintiffs to
exercise their stock options. The plaintiffs filed the case on October 2, 2000,
seeking damages in excess of $13 million. The Company has responded, denying
plaintiffs' allegations and the case is in the early stages of discovery.
Mediation is currently scheduled for late April and a preliminary trial date
has been set for June. Seven Seas intends to vigorously defend the case.

FORMER EMPLOYEE

A lawsuit has been filed against GHK Company Colombia in the Bogota labor
court by a former employee who claims that he incurred $1.6 million in expenses
in connection with a criminal action filed against him in Guaduas. Our Colombian
legal counsel has advised us that it is unlikely that we will lose the lawsuit
due the fact that, upon his departure from service, the plaintiff acknowledged
that GHK had paid in full all monies owed.

The Company is, from time to time, party to certain legal actions and claims
arising in the ordinary course of business. While the outcome of these events
cannot be predicted with certainty, management does not expect these matters to
have a material adverse effect on the financial position or results of
operations or cash flows of the Company.

13. RELATED PARTY TRANSACTIONS:

On November 1, 1997, the Company's Executive Vice President and Chief
Operating Officer obtained a $200,000 loan from the Company. This loan bears a
6.06% interest rate and is due November 1, 2002. The Company recognized interest
income of $12,000 in 2000, 1999 and 1998, respectively.

The Company's Chairman and Chief Executive Officer, Mr. Robert A. Hefner
III, beneficially owns 100% of The GHK Company LLC ("GHK"). Effective July 1,
1997, the Company has entered into an administrative service agreement with GHK.
The Company recognized expenses related to this agreement of $21,000, $21,000
and $28,000 in 2000, 1999 and 1998, respectively. In addition, GHK pays certain
miscellaneous costs incurred on behalf of the Company. The Company reimbursed
GHK $23,000, $31,000 and $0.1 million in 2000, 1999 and 1998, respectively, for
such costs.

Mr. Hefner, owns 100% of the shares of The GHK Corporation ("GHK Corp.").
GHK Corp. owns an executive aircraft, which Mr. Hefner and other Seven Seas
executives and employees use for certain business travel. The Company has
entered into an agreement with GHK Corp. whereby the Company pays GHK Corp. the
lesser of the cost of a first class airline ticket or the total actual expenses
for each specific flight. The Company had $24,000, $57,000 and $31,000 in
expenditures for such air travel during 2000, 1999 and 1998, respectively.

In December 2000, the Company entered into a loan agreement with Stillwater
National Bank and Trust Company, N.A. Mr. Hefner guaranteed this loan and
received $62,500 in remuneration for the guarantee.

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45

McAfee & Taft, A Professional Corporation, serves as Seven Seas' corporate
counsel. Gary F. Fuller is a shareholder of McAfee & Taft and has been a member
of Seven Seas' board of directors since 1997. The Company incurred expenses from
McAfee & Taft in the amounts of $499,340, $267,368 and $45,955 in 2000, 1999 and
1998, respectively.

14. MINORITY INTEREST:

In June 1999, Seven Seas Petroleum Inc. ("SSPI") completed the
reorganization of certain of its subsidiaries, three of which owned working
interests in the Dindal and Rio Seco association contracts, through a series of
tax-free transactions. Prior to these transactions, Seven Seas Petroleum
Holdings Inc (SSPH), a wholly owned subsidiary of SSPI, owned 100% of the stock
of Seven Seas Petroleum Colombia Inc. ("SSPC") and 50% of Esmeralda L.L.C. SSPC
owned the remaining 50% of Esmeralda L.L.C. and 62.963% of Cimarrona L.L.C. with
MTV Investments Ltd. ("MTV"), the minority interest owner in Cimarrona L.L.C.,
owning the remaining 37.037%. In the reorganization transactions, SSPH first
assigned its membership interest in Esmeralda L.L.C. to SSPC as a capital
contribution, giving SSPC 100% ownership of Esmeralda L.L.C. Next, Esmeralda
L.L.C. was merged into Cimarrona L.L.C. SSPH continued to own 100% of the stock
of SSPC. Cimarrona L.L.C. and its members, MTV and SSPC, entered into an
agreement whereby the assets, obligations, and liabilities of Cimarrona L.L.C.
which were proportionately attributable to SSPC (through the Company's interests
in Esmeralda L.L.C. and Cimarrona L.L.C.) were merged into SSPC in exchange for
SSPC's interest in Cimarrona L.L.C. As a result, MTV became the sole member of
Cimarrona L.L.C. and accordingly, Cimarrona L.L.C. is no longer a consolidated
subsidiary of the Company. In summary, MTV maintained its proportionate interest
in the Dindal and Rio Seco association contracts as a working interest owner and
Seven Seas' net interest in the association contracts was not changed.

15. SUBSEQUENT EVENTS:

In February 2001, the Company acquired a 100% interest in the Deep Dindal
association contract, subject to an obligation to assign certain of those
interests to Sipetrol and Cimarrona, its partners in the Guaduas Oil Field.
Following the drilling of a exploration well on the Deep Dindal association
contract, the Company will have to assign either a 25.85% collective interest to
Sipetrol and Cimarrona, or a 9.4% interest percent to Cimarrona and provide
Sipetrol with a 4.86% overriding royalty interest that is reducible by Colombian
government participation in the project.

Also in February 2001, the Company acquired a 100% interest in the Cristales
association contract, located immediately to the east of the Dindal and Deep
Dindal association contracts.

The Company released the Montecristo association contract. No oil and gas
reserves were attributable to this contract area.

On February 28, 2001, Seven Seas shareholders approved a proposal to
continue the Company to the Cayman Islands from the Yukon Territory. Effective
March 1, 2001, Seven Seas was continued as a Cayman Island company. See Note 6.

In March 2001, Seven Seas announced that it had hired Ronald A. Lefaive as
Vice-President of Finance and Chief Financial Officer.

On March 30, 2001, the Company extended the maturity date on its $10 million
loan with Stillwater National Bank and Trust Company from December 31, 2001 to
April 1, 2002.

SUPPLEMENTAL OIL AND GAS INFORMATION (UNAUDITED):

Capitalized costs at December 31, 2000, 1999 and 1998 respectively, relating
to the Company's oil and gas activities are shown below (In thousands):

COLOMBIA OTHERS TOTAL
-------- -------- --------

As of December 31, 2000
Proved properties .......... $117,106 $ -- $117,106
======== ======== ========
Unproved properties ........ $105,494 $ 41 $105,535
======== ======== ========
As of December 31, 1999
Proved properties .......... $ 97,008 $ -- $ 97,008
======== ======== ========
Unproved properties ........ $105,684 $ 41 $105,725
======== ======== ========
As of December 31, 1998
Proved properties .......... $ 74,993 $ -- $ 74,993
======== ======== ========
Unproved properties ........ $112,655 $ 461 $113,116
======== ======== ========

The above costs include capitalized interest of $13.2 million, $13.8 million
and $9.8 million for the years ended December 31, 2000, 1999 and 1998,
respectively.

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Costs incurred during the years ended December 31, 2000, 1999 and 1998,
respectively, were as follows (In thousands):

COLOMBIA OTHERS TOTAL
-------- -------- --------

Year ended December 31, 2000
Development cost ....................... $ 1,731 $ -- $ 1,731
Property acquisition cost:
Proved ............................... -- -- --
Unproved ............................. -- -- --
Exploration cost ....................... 18,177 -- 18,177
-------- -------- --------
Total cost incurred .......... $ 19,908 $ -- $ 19,908
======== ======== ========
Year ended December 31, 1999
Development cost ....................... $ -- $ -- $ --
Property acquisition cost:
Proved ............................... -- -- --
Unproved ............................. -- -- --
Exploration cost ....................... 26,453 250 26,703
-------- -------- --------
Total cost incurred .......... $ 26,453 $ 250 $ 26,703
======== ======== ========
Year ended December 31, 1998
Development cost ....................... $ -- $ -- $ --
Property acquisition cost:
Proved ............................... -- -- --
Unproved ............................. 160 -- 160
Exploration cost ....................... 50,387 115 50,502
-------- -------- --------
Total cost incurred .......... $ 50,547 $ 115 $ 50,662
======== ======== ========

The Company had oil and gas sales of $4.6 million, $2.3 million, and $.02
million in 2000, 1999 and 1998, respectively. The Company recognized $0.7
million and $0.8 million for depletion during 2000 and 1999, respectively.

EXPLORATION COSTS

The Company has been involved in exploration activities in Colombia,
Australia, Argentina, Turkey and Papua New Guinea. The Company purchased an
option for the right to participate in future exploration activities in North
Africa, but the option was never exercised. Additionally, the Company acquired
oil and gas properties in Colombia totaling zero, zero, and $.1 million in 2000,
1999, and 1998, respectively. There were deferred income taxes included in
capitalized acquisition costs during 2000, 1999 and 1998, as disclosed in
Note 2.

Ecopetrol has the right to back into Seven Seas' participating interest in
the Colombian association contracts at the start of the development stage of any
oil and gas discovery made on a given association contract area. Ecopetrol's
interest will commence at between 30% and 50% depending on the terms of the
association contract and will increase to between 65% and 75% as the volume of
oil production increases. Should Ecopetrol elect to participate in the
development and production of an oil and gas field, it will pay its share of the
future development costs and will pay some portion of the exploration costs
incurred prior to its decision to participate. In May 2000, Ecopetrol elected
not to participate in the development and exploration of the Guaduas Oil Field.
Seven Seas and its Guaduas Oil Field partners have elected to proceed on a
sole-risk basis pursuant to the terms of the Dindal and Rio Seco association
contracts. Ecopetrol retains the right to participate at a later date subject to
Seven Seas and it partners recovering 200% of the costs incurred since
Ecopetrol's May 2000 decision not to participate plus certain exploration costs.

PROVED RESERVES (UNAUDITED)

Proved reserves represent estimated quantities of crude oil which geological
and engineering data demonstrated to be reasonably certain of recoverability in
the future from known reservoirs under existing economic and operating
conditions. The accuracy of any reserve estimate is a function of the quantity
and quality of available data and of engineering and geological interpretation
and judgment.

Results of drilling, testing and production subsequent to the date of the
estimate may justify revision of such estimate. Additionally, the estimated
volumes to be commercially recoverable may fluctuate with changes in the price
of oil. Estimates of proved reserves have been determined using the most
economic development strategy; however, the Company is currently in the
development stage and has several critical steps to realize such commercial
economic production (see Note 1). These critical steps constitute significant
assumptions made in the estimate of the proved reserves and include, among other
assumptions, declaration of commerciality by Ecopetrol, costs associated with
the construction of a pipeline and production facilities and additional
developmental drilling. Additionally, the reserve estimates assume that future
production will be transported to existing pipelines through the proposed
pipeline to market and that capacity will be available or existing pipelines for
the Company's production.

Estimates of future recoverable oil reserves and projected future net
revenues for all periods presented were provided by Ryder Scott Company
Petroleum Consultants. The Company's proved reserves were comprised entirely of
crude oil in Colombia.

Proved developed and undeveloped reserves (barrels):

2000 1999 1998
------------ ------------ ------------

Beginning of year ................. 34,879,888 38,719,235 32,160,245
Extensions and discoveries ........ -- -- --
Revision of estimate .............. 13,112,068 (3,839,347) 6,558,990
------------ ------------ ------------
End of year ....................... 47,991,956 34,879,888 38,719,235
============ ============ ============
Proved developed .................. 15,853,372 11,000,540 20,238,430
============ ============ ============

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The following table presents the Standardized Measure of Discounted Future
Net Cash Flows relating to proved oil reserves. Future cash inflows and costs
were computed using prices and costs in effect at the end of the year without
escalation less a gravity and transportation adjustment of $8.64 to reference
prices. The reference price for the year ended December 31, 2000 was West Texas
Intermediate of $26.80 per barrel. Future income taxes were computed by applying
the appropriate statutory income tax rate to the pretax future net cash flows
reduced by future tax deductions and net operating loss carryforwards.

Standardized Measure of Discounted Future Net Cash Flows (In thousands):

2000 1999 1998
-------- -------- --------

Future cash inflows ........................................ $871,534 $735,965 $292,292
Future costs
Production ............................................... 131,944 92,958 32,543
Development .............................................. 69,522 37,404 33,574
Future income taxes ........................................ 201,315 183,387 64,632
-------- -------- --------
Future net cash flows ...................................... 468,753 422,216 161,543
10% discount factor ........................................ 179,408 191,249 71,693
-------- -------- --------
Standardized measure of discounted future net cash
flows .................................................... $289,345 $230,967 $ 89,850
======== ======== ========

Principal sources of changes in the Standardized Measure of Discounted
Future Net Cash Flows during 2000, 1999 and 1998 (In thousands):

2000 1999 1998
---------- ---------- ----------

Beginning of year .......................................... $ 230,967 $ 89,850 $ 100,617
Sales and transfers of net production costs ................ (2,020) -- --
Net change in price and production costs ................... (54,573) 230,452 (35,777)
Extensions, discoveries, and additions, less related
costs .................................................... -- -- --
Revision of quantity estimates ............................. 103,766 (36,260) 26,373
Net change in future development costs ..................... 26,511 (3,830) 147
Net change in income taxes ................................. (24,303) (52,069) 18,221
Accretion of discount ...................................... 31,138 11,588 14,486
Changes in production rates and other ...................... (22,141) (8,764) (34,217)
---------- ---------- ----------
End of year ................................................ $ 289,345 $ 230,967 $ 89,850
========== ========== ==========

The Standardized Measure of Discounted Future Net Cash Flows shown above
relates to the Company's discovery of oil on the Association Contracts in
Colombia.

The Standardized Measure of Discounted Future Net Cash Flows does not
purport to present the fair market value of the Company's proved reserves. An
estimate of fair value would also take into account, among other things, the
recovery of reserves in excess of proved reserves, anticipated future changes in
prices and costs and a discount factor more representative of the time value of
money and the risks inherent in reserve estimates.

Under the full cost accounting rules of the U.S. Securities and Exchange
Commission, the Company reviews the carrying value of its proved oil and gas
properties each quarter on a country-by-country basis. Under these rules,
capitalized costs of proved oil and gas properties, net of accumulated
depletion, depreciation and amortization and deferred income taxes, may not
exceed the present value of estimated future net cash flows from proved oil and
gas reserves, discounted at 10 percent, plus the lower of cost or fair value of
unproved properties included in the costs of being amortized, net of related tax
effects. These rules generally require pricing future oil and gas production at
the unescalated oil and gas prices at the end of each fiscal quarter and require
a write-down if the "ceiling" is exceeded. Given the volatility of oil and gas
prices, it is reasonably possible that the Company's estimate of discounted
future net cash flows from proved oil and gas reserves could change in the near
term. If oil and gas price decline significantly, even if only for a short
period of time, it is possible that write-downs of oil and gas properties could
occur in the future.

SUPPLEMENTARY FINANCIAL INFORMATION

Selected Quarterly Data. Results of development stage operations by quarter
for the years ended December 31, 2000 and 1999 were (in thousands, except per
share amounts):

2000 QUARTER ENDED
------------------------------------------------------------
MARCH 31 JUNE 30 SEPTEMBER 30 DECEMBER 31
------------ ------------ ------------ ------------

Operating revenues ........... $ 568 $ 454 $ 2,334 $ 3,078
Less costs and expenses ...... 3,373 1,984 2,556 4,388
------------ ------------ ------------ ------------
(2,805) (1,530) (222) (1,310)
Net loss ..................... $ (2,805) $ (1,530) $ (242) $ (1,330)
============ ============ ============ ============
Net loss per share ........... $ (0.07) $ (0.04) $ (0.01) $ (0.04)
============ ============ ============ ============

1999 QUARTER ENDED
------------------------------------------------------------
MARCH 31 JUNE 30 SEPTEMBER 30 DECEMBER 31
------------ ------------ ------------ ------------

Operating revenues ........... $ 996 $ 887 $ 828 $ 2,602
Less costs and expenses ...... 2,207 5,134 2,104 3,188
------------ ------------ ------------ ------------
(1,211) (4,247) (1,276) (586)
Net loss ..................... $ (1,104) $ (3,781) $ (1,286) $ (618)
============ ============ ============ ============
Net loss per share ........... $ (0.03) $ (0.10) $ (0.03) $ (0.02)
============ ============ ============ ============

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ITEM 9. CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND
FINANCIAL DISCLOSURE

None

PART III

ITEM 10. DIRECTORS AND EXECUTIVE OFFICERS OF THE REGISTRANT

The following information, which was provided to us by the individuals,
shows each director and executive officer's (i) name and age; (ii) principal
positions with Seven Seas; (iii) principal occupation or employment during the
last five years; (iv) other public directorships and (v) starting date as a
director or executive officer. No family relationship exists among any of the
Seven Seas executive officers and directors.

PRESENT POSITION PRINCIPAL OCCUPATION DURING THE LAST COMMENCEMENT
NAME AGE WITH SEVEN SEAS FIVE YEARS; OTHER DIRECTORSHIPS WITH SEVEN SEAS
- ----------------------- --- ---------------- ------------------------------------ ---------------

R. Randolph Devening(2) ........ 58 Director President and Chief Executive 11/00
Officer of Foodbrands America, Inc.;
Director of Hancock Fabrics, Inc.,
Keystone Operations, Inc., and
Love's Travel Stops Country Stores, Inc.

Brian F. Egolf(2)(3)............ 52 Director President of Petroleum Properties 11/96
Management Corporation, a private
oil and gas exploration company

Gary F. Fuller(1)(3)............ 64 Director Shareholder of McAfee & Taft, 5/97
A Professional Corporation

Robert A. Hefner III(1)......... 66 Chairman, Chief Managing Member of The GHK Company 11/96
Executive Officer, L.L.C., a private oil and gas
Managing Director exploration company
and Director

Ronald A. Lefaive .............. 53 Vice President of Senior Manager of Global Administrative 3/01
Finance and Chief Services of Halliburton Company from
Financial Officer 1999 to March 2001; Senior Vice
President - Accounting, Controller and
Chief Accounting Officer at Chesapeake
Energy Corporation from 1993 to 1999

Robert B. Panero(2) ............ 72 Director President of Robert Panero Associates, 5/97
International Strategic Policy and
Project Studies Advisors

Larry A. Ray(1) ................ 53 President, Chief President since November 2000; Chief 6/97
Operating Officer, Operating Officer since September
Corporate 1997, Chief Financial Officer from
Secretary and April 1999 to March 2001; Executive
Director Vice President from September 1999
to November 2000; Executive Vice
President - Operations from June 1997
to September 1997

Dr. James R. Schlesinger(3) .... 72 Director Senior Advisor to the investment 9/99
banking firm Lehman Brothers;
Chairman of the Board of Trustees
of the MITRE Corporation

- ----------

(1) Member of the Executive Committee

(2) Member of the Audit Committee

(3) Member of the Compensation Committee

Each of our directors and officers has held the principal occupation
identified above for not less than five years, except for Mr. Lefaive, who
became an officer of Seven Seas in March 2001, Mr. Hefner, who became an officer
of Seven Seas in May 1997, and Mr. Ray, who was appointed President in November
2000 and Chief Operating Officer in September 1997.

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Prior to his association with the Company, Mr. Lefaive was employed by
Halliburton Company as a senior manager responsible for global administrative
services within the information technology department. From 1993 to 1999, he
served in various financial capacities within Chesapeake Energy Corporation in
Oklahoma City, Oklahoma, the last being Senior Vice President - Accounting,
Controller and Chief Accounting Officer. From 1991 to 1993, Mr. Lefaive was
Controller for Phibro Energy Production, Inc., an international exploration and
production subsidiary of Phibro Energy, whose principal operations were located
in Russia. From 1982 to 1991, Mr. Lefaive served as Assistant Controller,
General Auditor, and Manager of Management Information Systems at Conquest
Exploration Company in Houston, Texas. Prior to joining Conquest, Mr. Lefaive
held various financial staff and management positions with The Superior Oil
Company from 1980 to 1982 and Shell Oil Company from 1975 to 1982. Mr. Lefaive
is a Certified Public Accountant and graduated from the University of Houston in
1975.

Mr. Ray served as Seven Seas' Executive Vice President from September 1997
to November 2000 and was appointed Chief Financial Officer of Seven Seas on an
interim basis between April 1999 and March 2001. From June 1997 to September
1997, Mr. Ray served as Seven Seas' Executive Vice President of Operations.
Prior to joining Seven Seas, Mr. Ray served in a management capacity for The GHK
Company L.L.C.

OTHER KEY EMPLOYEES

During the first quarter of 2000, we hired J. Anthony Stuart, a 22-year
employee of British Petroleum, as our drilling manager in our Bogota office. Mr.
Stuart had spent the previous nine years working for BP in Colombia on the
development of the Cusiana-Cupiagua field, Colombia's largest known oil field.
At the time of his retirement from BP, Mr. Stuart was serving as Drilling
Operations Manager. In early 2001, we made Mr. Stuart Vice President of
Operations of GHK Company Colombia, our subsidiary in Colombia and the operator
of the Guaduas Oil Field. Mr. Stuart will oversee the drilling of the subthrust
exploration well provided it is drilled this year. Concurrent with Mr. Stuart's
promotion, we also named Claudia M. Vaca Vice President of Legal, Finance and
Administration of GHK Company Colombia. Prior to this position, Ms. Vaca, who is
a graduate of the Harvard Law School, was serving as GHK Company Colombia's
General Counsel.

SECTION 16(a) BENEFICIAL OWNERSHIP REPORTING COMPLIANCE

The following of Seven Seas' directors, officers and 10% beneficial owners
filed untimely reports required by Section 16(a) of the Securities Exchange Act
of 1934 during the 2000 fiscal year: William W. Daily and Breene M. Kerr failed
to file a required Form 5; R. Randolph Devening filed an untimely Form 3; and
each of Robert A. Hefner III, Larry A. Ray, Brian F. Egolf, Gary F. Fuller,
Robert B. Panero, Dr. James R. Schlesinger and Sir Mark Thomson Bt. filed an
untimely Form 5.

ITEM 11. EXECUTIVE COMPENSATION

Directors who are not officers or employees are paid such remuneration as
the board determines and are eligible to participate in our 1996 and 1997 stock
option plans. They are also reimbursed for their out-of-pocket expenses incurred
in connection with their services as directors, including travel expenses. We
also maintain directors' and officers' insurance.

Mr. Hefner was awarded options to purchase 221,108 common shares in lieu of
cash compensation of $450,000 for services provided and to be provided from
August 1, 1999 through July 31, 2000. On August 13, 1999, Mr. Hefner began
receiving, in lieu of cash compensation, options to purchase 9,213 common shares
semi-monthly, on our payroll days, through July 31, 2000. Such options vest upon
receipt and are priced at the average of the high and low trading price on the
American Stock Exchange on each respective payroll day. Mr. Hefner was also
awarded options to purchase 423,888 common shares in lieu of cash compensation
of $450,000 for services provided from August 1, 2000 through July 31, 2001. Mr.
Hefner received options to purchase 17,662 common shares semi-monthly, on our
payroll days between August 1, 2000 and February 28, 2001. Instead of receiving
options to purchase 17,662 common shares semi-monthly through July 31, 2001, Mr.
Hefner will receive options to purchase 88,310 common shares on May 15, 2001 and
July 30, 2001. The exercise price is the average of the high and low trading
price on the American Stock Exchange on each respective grant date.

Sir Mark Thomson Bt. was awarded options to purchase 350,000 common shares
vesting on October 31, 2000 at an exercise price of $4.2 per share, an amount
greater than the fair market value of the stock on the date awarded.

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50

On September 30, 2000, Dr. Schlesinger was awarded options to purchase 822
common shares at an exercise price of $2.9375 for his service as a second year
director during third quarter 2000. On December 31, 2000, Dr. Schlesinger was
awarded options to purchase 7,061 common shares at an exercise price of $1.2813
for his service as a second-year director during fourth quarter 2000.

Non-employee directors who had been directors for more than one year at the
end of 1999 were awarded options to purchase 23,260 common shares in lieu of
cash compensation of $35,000 for services provided during 2000. Independent
directors serving on the Audit Committee for 2000 were awarded options to
purchase 24,922 common shares; those serving on the Compensation Committee were
awarded options to purchase 28,245 common shares; and independent directors
serving on both the Compensation Committee and the Audit Committee for 2000 were
awarded options to purchase 29,906 common shares in lieu of compensation.
Accordingly, Mr. Egolf was awarded 29,206 options; Mr. Fuller was awarded 29,206
options; and Mr. Panero was awarded 24,922 options. One-quarter of the options
awarded in 2000 to each independent director were granted on March 31, 2000,
June 30, 2000, September 30, 2000 and December 31, 2000. The exercise price for
all the options granted to non-employee directors in 2000 was the average
between the high and low trading prices on the American Stock Exchange on the
date of grant. All options vested immediately upon grant and will expire on July
30, 2004, if not sooner exercised.

On November 13, 2000, Mr. Devening was awarded options to purchase 75,000
common shares at an exercise price of $2.781 per share, of which options to
purchase 25,000 common shares vested immediately and options to purchase 25,000
common shares vest on each of November, 2001 and 2002.

On April 7, 2000, Mr. Ray was awarded options to purchase 200,000 common
shares at an exercise price of $3.00, an amount greater than the fair market
value of the shares at the time of grant. One-quarter of these options vest six
months after the date of grant, one-quarter vest twelve months after the date of
grant, one-quarter vest eighteen months after the date of grant, and one-quarter
vest twenty-four months after the date of grant.

SUMMARY COMPENSATION TABLE

The following table sets forth certain summary information regarding the
compensation Seven Seas paid to our Chief Executive Officer and our other three
most highly compensated officers whose total compensation during the fiscal year
ended December 31, 2000 exceeded $100,000.

ANNUAL COMPENSATION LONG TERM COMPENSATION AWARDS
------------------------------------ ----------------------------------------------------
PAYOUTS
RESTRICTED SECURITIES -------
OTHER ANNUAL STOCK UNDERLYING LTIP ALL OTHER
NAME AND PRINCIPAL POSITION YEAR SALARY BONUS COMPENSATION(1) AWARD OPTIONS PAYOUTS COMPENSATION
- --------------------------- ---- --------- ----- --------------- ---------- ---------- ------- -------------

Robert A. Hefner, III,..... 2000 $ -- -- -- -- 305,598 -- --
Chairman and Chief Executive 1999 281,250 -- -- -- 92,130 -- --
Officer 1998 450,000 -- -- -- -- -- --

Sir Mark Thomson, Bt,...... 2000 $ 370,313 -- -- -- -- --
President and Director 1999 295,160 -- -- -- 350,000 -- --
1998 -- -- -- -- -- -- --

Larry A. Ray,.............. 2000 $ 334,417 -- 200,000
President, Chief Operating 1999 300,000 -- -- -- 550,000 -- --
Officer, Corporate Secretary 1998 262,500 -- -- -- -- -- --
and Director

William W. Daily,.......... 2000 $ 25,397(2) -- $342,494(3)
Executive Vice President, 1999 330,000 -- -- -- -- -- --
President of GHK Company 1998 120,000(4) -- -- -- 237,500 -- --
Colombia and Director

- ----------

(1) Except as otherwise indicated, the dollar value of perquisites and other
personal benefits for each of the named executive officers was less than
established reporting thresholds and did not exceed the lesser of $50,000 or
10% of combined salary and bonus in each year covered.

(2) Represents salary received from January 1, 2000 through January 28, 2000
from Seven Seas, which amount does not reflect an annual rate of
compensation.

(3) Represents termination payment from Seven Seas pursuant to severance
agreement dated January 28, 2000, including payroll tax.

50
51

(4) Represents salary received from commencement of employment through December
31, 1998 from Seven Seas, which amount does not reflect an annual rate of
compensation.

OPTION GRANTS DURING 2000

The following table sets forth information regarding individual grants of
options by Seven Seas during the fiscal year ended December 31, 2000 to the
named executive officers and their potential realizable values.

INDIVIDUAL GRANTS
------------------------------------------------
POTENTIAL REALIZABLE
% OF TOTAL MARKET VALUE AT ASSUMED
NUMBER OF OPTION VALUE ANNUAL RATES OF SHARE
SHARES GRANTED TO EXERCISE PER SHARE PRICE APPRECIATION FOR
UNDERLYING EMPLOYEES OR BASE ON THE OPTION TERM(1)
OPTIONS IN FISCAL PRICE PER DATE OF EXPIRATION ----------------------
NAME GRANTED YEAR SHARE GRANT DATE 5% 10%
- ---- ---------- ---------- --------- --------- ---------- -------- --------

Robert A. Hefner, III... 9,213(2) 0.90% 2.00 2.00 07/30/04 11,588 29,366
Robert A. Hefner, III... 9,213(2) 0.90% 2.00 2.00 07/30/04 11,588 29,366
Robert A. Hefner, III... 9,213 0.90% 2.13 2.13 07/30/04 12,312 31,202
Robert A. Hefner, III... 9,213 0.90% 2.00 2.00 07/30/04 11,588 29,366
Robert A. Hefner, III... 9,213 0.90% 2.69 2.69 07/30/04 15,571 39,461
Robert A. Hefner, III... 9,213 0.90% 1.94 1.94 07/30/04 11,226 28,449
Robert A. Hefner, III... 9,213 0.90% 1.81 1.81 07/30/04 10,502 26,613
Robert A. Hefner, III... 9,213 0.90% 1.75 1.75 07/30/04 10,140 25,696
Robert A. Hefner, III... 9,213 0.90% 1.13 1.13 07/30/04 6,518 16,519
Robert A. Hefner, III... 9,213 0.90% 1.06 1.06 07/30/04 6,156 15,601
Robert A. Hefner, III... 9,213 0.90% 1.47 1.47 07/30/04 8,510 21,566
Robert A. Hefner, III... 9,213 0.90% 1.19 1.19 07/30/04 6,880 17,436
Robert A. Hefner, III... 9,213 0.90% 1.09 1.09 07/30/04 6,337 16,060
Robert A. Hefner, III... 9,209 0.90% 1.28 1.28 07/30/04 7,420 18,805
Robert A. Hefner, III... 35,324 3.44% 2.81 2.81 07/30/05 62,480 158,336
Robert A. Hefner, III... 17,662 1.72% 3.22 3.22 07/30/05 35,752 90,604
Robert A. Hefner, III... 17,662 1.72% 2.94 2.94 07/30/05 32,628 82,687
Robert A. Hefner, III... 17,662 1.72% 2.47 2.47 07/30/05 27,422 69,492
Robert A. Hefner, III... 17,662 1.72% 2.69 2.69 07/30/05 29,852 75,650
Robert A. Hefner, III... 17,662 1.72% 2.81 2.81 07/30/05 31,240 79,168
Robert A. Hefner, III... 17,662 1.72% 1.75 1.75 07/30/05 19,438 49,260
Robert A. Hefner, III... 17,662 1.72% 1.47 1.47 07/30/05 16,314 41,343
Robert A. Hefner, III... 17,662 1.72% 1.28 1.28 07/30/05 14,232 36,065
Larry A. Ray............ 200,000 19.50% 3.00 2.03 04/07/10 377,337 956,245

- ----------

(1) The assumed rates of annual appreciation are calculated from the date of
grant through the assumed expiration date. Actual gains, if any, on option
exercises and common share holdings are dependent on the future performance
of the common shares and overall stock market conditions. There can be no
assurance that the value reflected in the table will be achieved.

(2) Options exercisable when stock trades above $10.90.

We have not granted any stock appreciation rights to the named executive
officers or to our other employees or directors.

AGGREGATED OPTION EXERCISES DURING 2000 AND FISCAL YEAR-END OPTION VALUES

The following table provides information relating to options exercised by
the named executive officers during 2000 and the number and value of unexercised
options held by the named executive officers at year-end. Seven Seas does not
have any outstanding stock appreciation rights:

NUMBER OF SECURITIES
UNDERLYING VALUE OF UNEXERCISED
UNEXERCISED OPTIONS, IN-THE-MONEY OPTIONS,
SHARES SECURITIES UNDERLYING UNEXERCISED OPTIONS VALUE OF UNEXERCISED IN-THE-MONEY OPTIONS
ACQUIRED VALUE AT DECEMBER 31, 2000 AT DECEMBER 31, 2000
ON REALIZED ----------------------------------------- -----------------------------------------
NAME EXERCISE (1) EXERCISABLE UNEXERCISABLE EXERCISABLE UNEXERCISABLE
- ---- -------- -------- ----------- ------------- ----------- -------------

Robert A. Hefner, III.. -- -- 897,728 -- $9,141.38 --
Sir Mark Thomson, Bt... -- -- 450,000 -- -- --
Larry A. Ray........... -- -- 466,666 283,334 -- --
William W. Daily(3).... -- -- 237,500 -- -- --

- ----------

(1) Represents the difference between the exercise price of the option and the
closing price on the date of exercise.

51
52

(2) Based on a closing price on December 31, 2000 of $1.38 per share. Options
are "in-the-money" at the fiscal year-end if the market value of the
underlying securities on that date exceeds the exercise price of the option.

(3) The options granted to Mr. Daily vested immediately on January 20, 2000,
pursuant to his severance agreement.

EMPLOYMENT AGREEMENTS

We entered into a five-year employment agreement with Larry A. Ray dated
June 12, 1997 that provides for an annual base salary of $262,500 and also
provides that, in the sole discretion of the Compensation Committee of the
board, Mr. Ray may receive annual merit increases, annual bonuses and stock
option awards. As part of his employment agreement, Mr. Ray was granted options
to purchase 200,000 common shares at an exercise price of $10.70 per share.
One-third of the options vested immediately and the remainder vest one-half each
on the first and second anniversaries of the date of grant. The employment
agreement may be terminated for cause, which includes death or serious
incapacity. Under the terms of the employment agreement, Mr. Ray will receive
payments equal to the amounts remaining to be paid under the agreement in the
event of a change in control or if his employment terminates for any reason. For
purposes of this agreement, the term "change in control" means:

o any merger, consolidation or reorganization in which Seven Seas is not
the surviving entity (or survives only as a subsidiary of an entity);

o any sale, lease, exchange or other transfer of (or agreement to sell,
lease, exchange or otherwise transfer) all or substantially all of our
assets to any other person or entity (in one transaction or a series of
related transactions);

o dissolution or liquidation of Seven Seas;

o any person or entity, including a group as contemplated by Section 13(d)
of the Exchange Act, acquires or gains ownership or control (including
without limitation, power to vote) of more than 45% of the outstanding
shares of our voting stock (based upon voting power); or

o as a result of or in connection with a contested election of directors,
the persons who were directors of Seven Seas before the election cease
to constitute a majority of the board of directors; provided, however,
that the term "change in control" does not include any reorganization,
merger, consolidation, sale, lease, exchange or similar transaction
involving solely Seven Seas and one or more previously wholly-owned
subsidiaries of Seven Seas.

We entered into a three-year employment agreement with William W. Daily
dated September 1, 1998 that provided for an annual base salary of $330,000. Mr.
Daily was also entitled to receive annual merit increases, annual bonuses and
stock option awards, at the sole discretion of the Compensation Committee. As a
part of his employment agreement, Mr. Daily was granted options to purchase
237,500 common shares at an exercise price of $9.00 per share. The remaining
terms of his employment agreement were substantially similar to Mr. Ray's
employment agreement. Mr. Daily resigned his employment with Seven Seas
effective January 28, 2000. Under the terms of a severance agreement with Mr.
Daily dated January 28, 2000, we agreed to pay a termination payment of $330,000
to Mr. Daily and all options granted to him vested immediately.

We entered into a fifteen-month employment agreement with Sir Mark Thomson,
Bt dated August 1, 1999 that provided for an annual base salary of $450,000.
Upon signing, Sir Mark Thomson Bt received a signing bonus of $107,660 for
services provided to Seven Seas prior to the date of his employment agreement.
The employment agreement also provided that other such bonuses, if any, could be
awarded at the sole discretion of the Compensation Committee. As a part of his
employment agreement, Sir Mark Thomson Bt was granted options to purchase
350,000 common shares at an exercise price of $4.2 per share, such options to
vest October 31, 2000 or upon the occurrence of a change in control. Sir Mark
Thomson Bt. was also eligible to receive other stock option grants at our
discretion. The remaining terms of the employment agreement were substantially
similar to Mr. Ray's employment agreement. Sir Mark Thomson Bt's tenure with the
company lapsed on October 31, 2000 pursuant to the terms of his employee
agreement.

ITEM 12. SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT

Below, we have listed information as of March 15, 2001, about the beneficial
ownership of the common shares. This table shows ownership by (i) each person
who we know beneficially owns more than 5% of the issued and outstanding common
shares, (ii) each director and each of the named officers and (iii) all of our
executive officers and directors as a group.

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53

NUMBER OF PERCENT
BENEFICIAL OWNER COMMON SHARES(1) OF CLASS
- ---------------- ---------------- --------

Robert A. Hefner, III...................... 5,839,937(2) 15.0%
c/o Seven Seas Petroleum, Inc.
Suite 1700, 5555 San Felipe
Houston, Texas 77056

Breene M. Kerr............................. 2,733,031(3) 7.2%
c/o Brookside Company
115 Bay Street
Easton, MD 21601

State Street Research & Management Company. 2,262,300(4) 6.0%
One Financial Centre, 30th Floor
Boston, Massachusetts 02111

Robert W. Moore............................ 2,542,000 6.7%
MTV Limited Partnership
3600 West Main Street, Suite 150
Norman, Oklahoma 73072

Larry A. Ray............................... 623,886(5) 1.6%
Brian F. Egolf............................. 336,269(6) *
Gary F. Fuller............................. 223,899(7) *
Robert B. Panero........................... 118,259(8) *
Dr. James R. Schlesinger................... 63,305(9) *
R. Randolph Devening....................... 25,000(10) *
All executive officers and directors as a
group (7 persons)........................ 7,230,555(11) 18.7%

- ----------
* Less than 1%

(1) Unless we indicated otherwise, each of the parties listed has sole
voting and investment power over the shares owned. The number of shares
listed includes the number of common shares that would be issued if
certain stock options that are currently exercisable were exercised
subject to our Amended 1996 Stock Option Plan and our 1997 Stock Option
Plan. For purposes of this table, options are deemed to be currently
exercisable if they may be exercised within 60 days following March 29,
2001.

(2) Includes 1,056,686 common shares currently issuable upon exercise of
options and 15,000 common shares held by an entity in which Mr. Hefner
has a substantial interest.

(3) Includes 172,112 common shares currently issuable upon exercise of
options and 2,560,919 common shares beneficially owned by a limited
partnership in which Mr. Kerr serves as a general partner.

(4) Based on a Schedule 13G for the year ended December 31, 2000, State
Street has sole power to vote 2,168,400 shares and sole power to
dispose of 2,262,300 shares.

(5) Includes 516,666 common shares currently issuable upon exercise of
options, 2,720 shares in Mr. Ray's retirement account and an additional
104,500 owned by Mr. Ray's wife.

(6) Includes 274,533 common shares currently issuable upon exercise of
options and 25,000 common shares owned by a trust for the benefit of
members of Mr. Egolf's family.

(7) Includes 208,399 common shares currently issuable upon exercise of
options. Also includes 4,000 common shares owned by a limited liability
company, of which Mr. Fuller and his wife each own a 50% interest and
share voting and investment powers, and 10,000 common shares owned by a
limited partnership of which Mr. Fuller has the voting and investment
power as a trustee of a trust which is the sole general partner. Mr.
Fuller has a 35.65% interest in the partnership as a limited partner.
Also includes 3,500 common shares owned by Mr. Fuller's wife as to
which he disclaims beneficial ownership.

(8) Includes 117,480 common shares currently issuable upon exercise of
options and 779 common shares held by Mr. Panero's wife.

(9) Includes 63,305 common shares currently issuable upon exercise of
options.

(10) Includes 25,000 common shares currently issuable upon exercise of
options.

(11) Includes 2,262,069 common shares currently issuable upon exercise of
options.

ITEM 13. CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS

On November 1, 1997, the Executive Vice President and Chief Operating
Officer obtained a $200,000 loan from the Company. This loan bears a 6.06%
interest rate and is due November 1, 2002. The Company recognized interest
income of $12,000 in 2000, 1999 and 1998, respectively.

53
54

The Company's Chairman and Chief Executive Officer, Mr. Robert A. Hefner
III, beneficially owns 100% of The GHK Company LLC ("GHK"). Effective July 1,
1997, the Company has entered into an administrative service agreement with GHK.
The Company recognized $21,000, $21,000 and $28,000 of such expenses in 2000,
1999 and 1998, respectively. In addition, GHK pays certain miscellaneous costs
incurred on behalf of the Company. The Company reimbursed GHK $23,000, $31,000
and $0.1 million in 2000, 1999 and 1998, respectively, for such costs.

Mr. Hefner owns 100% of the shares of The GHK Corporation ("GHK Corp."). GHK
Corp. owns an executive aircraft, which Mr. Hefner and other Seven Seas
executives and employees use for certain business travel. The Company has
entered into an agreement with GHK Corp. whereby the Company pays GHK Corp. the
lesser of the cost of a first class airline ticket or the total actual expenses
for each specific flight. The Company had $24,000, $57,000 and $31,000 in
expenditures for such air travel during 2000, 1999 and 1998, respectively.

PART IV

ITEM 14. EXHIBITS, FINANCIAL STATEMENT SCHEDULES, AND REPORTS ON FORM 8-K

(a) Financial Statements and Schedules:

(1) Financial Statements: The financial statements required to be filed are
included under Item 8 of this report.

(2) Schedules: All schedules for which provision is made in applicable
accounting regulations of the SEC have been omitted as the schedules are either
not required under the related instructions, are not applicable or the
information required thereby is set forth in the Company's Consolidated
Financial Statements or the Notes thereto.

(3) Exhibits:

The following instruments and documents are included as Exhibits to this
document. Exhibits incorporated by reference are so indicated by parenthetical
information.

EXHIBIT
NUMBER DESCRIPTION

(3) Articles of Incorporation and By-laws

(A)* Certificate of Continuance to the
Cayman Islands

(B)* Memorandum of Association

(C)* Articles of Association

(4) Instruments defining the rights of
security holders, including indentures

(A) Indenture dated as of May 7, 1998
between Seven Seas Petroleum Inc., a
Yukon Territory, Canada corporation,
and The Bank of Nova Scotia Trust
Company of New York, as Trustee,
incorporated by reference to Exhibit
4(A) in Registration on Form S-4 filed
on July 2, 1998 (File No. 333-58499)

(B) Registration Rights Agreement dated as
of May 7, 1998 among Seven Seas
Petroleum Inc., a Yukon Territory,
Canada corporation, and the Initial
Purchasers, incorporated by reference
to Exhibit 4(B) in Registration on
Form S-4 filed on July 2, 1998 (File
No. 333-58499)

(C) Collateral Pledge and Security
Agreement dated as of May 7, 1998
between Seven Seas Petroleum Inc., a
Yukon Territory, Canada corporation,
and The Bank of Nova Scotia Trust
Company of New York, as Trustee,
incorporated by reference to Exhibit
4(C) in Registration on Form S-4 filed
on July 2, 1998 (File No. 333-58499)

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55

(10) Material Contracts

(A) Letter Agreement dated August 14, 1995
by and between Seven Seas Petroleum
Inc., a Yukon Territory, Canada
corporation, and GHK Company Columbia,
as amended by letter agreement dated
November 30, 1995, incorporated by
reference to Exhibit 10(A) in
Registration on Form 10 filed April
30, 1997 (File No. 000-22483)

(B) The Association Contract by and
between Ecopetrol and GHK Company
Colombia and Petrolinson, S.A.
relating to the Dindal block, as
amended, incorporated by reference to
Exhibit 10(B) in Registration on Form
10 filed April 30, 1997 (File No.
000-22483)

(C) The Association Contract by and
between Ecopetrol and GHK Company
Colombia relating to the Rio Seco
block, incorporated by reference to
Exhibit 10(C) in Registration on Form
10 filed April 30, 1997 (File No.
000-22483)

(D) Joint Operating Agreement dated as of
August 1, 1994 by and between GHK
Company Colombia and the holder of
interests in the Dindal block,
incorporated by reference to Exhibit
10(D) in Registration on Form 10 filed
April 30, 1997 (File No. 000-22483)

(E) Management Services Agreement by and
among GHK Company Colombia, Seven Seas
Petroleum Inc., a Yukon Territory,
Canada corporation, and The GHK
Company L.L.C., incorporated by
reference to Exhibit 10(J) in
Registration on Form 10 filed April
30, 1997 (File No. 000-22483)

(F) Amended 1996 Stock Option Plan,
incorporated by reference to Exhibit
10(M) in Registration on Form 10 filed
April 30, 1997 (File No. 000-22483)

(G) Form of Incentive Stock Option
Agreement, incorporated by reference
to Exhibit 10(N) in Registration on
Form 10 filed April 30, 1997 (File No.
000-22483)

(H) Form of Directors' Stock Option
Agreement, incorporated by reference
to Exhibit 10(O) in Registration on
Form 10 filed April 30, 1997 (File No.
000-22483)

(I)** Form of Employment Agreement between
Seven Seas Petroleum Inc., a Yukon
Territory, Canada corporation, and
Larry A. Ray, incorporated by
reference to Exhibit 10(R) in
Registration on Amendment No. 1 to
Form 10, filed September 15, 1997
(File No. 000-22483)

(J) Settlement Agreement between Seven
Seas Petroleum Inc., a Yukon
Territory, Canada corporation, and Mr.
Whitehead dated May 20, 1997,
incorporated by reference to Exhibit
10(S) in Registration on Amendment No.
1 to Form 10, filed September 15, 1997
(File No.000-22483)

(K) 1997 Stock Option Plan, incorporated
by reference to Exhibit 10(BB) in
Registration on Amendment No. 1 to
Form 10 filed September 15, 1997 (File
No. 000-22483)

(L) The Association Contract by and
between Ecopetrol and Seven Seas
Petroleum Colombia relating to the
Rosablanca block, incorporated by
reference to Exhibit 10(B) on Form
10-K for the year ended December 31,
1997 (File No. 001-13771)

(M) The Association Contract by and
between Ecopetrol and Seven Seas
Petroleum Colombia relating to the
Montecristo block, incorporated by
reference to Exhibit 10(C) on Form
10-K for the year ended December 31,
1997 (File No. 001-13771)

(N)** Form of Employment Agreement between
Seven Seas Petroleum Inc., a Yukon
Territory, Canada corporation and Sir
Mark Thomson Bt, incorporated by
reference to Exhibit 10(V) on Form
10-K for the year ended December 31,
1999 (File No. 001-13771)

(O)** Severance Agreement with Herbert C.
Williamson III, incorporated by
reference to Exhibit 10(W) on Form
10-K for the year ended December 31,
1999 (File No. 001-13771)

55
56

(P)** Severance Agreement with William W.
Daily, incorporated by reference to
Exhibit 10(X) on Form 10-K for the
year ended December 31, 1999 (File No.
001-13771)

(Q) Memorandum of Understanding with
Empresa Colombiana de Petroleos,
incorporated by reference to Exhibit
10(Y) on Form 10-K for the year ended
December 31, 1999 (File No. 001-13771)

(R) Global Operating License, incorporated
by reference to Exhibit 10(W) on Form
S-4, filed January 10, 2001 (File No.
333-53470)

(S) Loan Agreement between Seven Seas
Petroleum Inc., a Yukon Territory,
Canada corporation, and Stillwater
National Bank and Trust Company, N.A.,
dated December 20, 2000, and related
Guaranty Agreement and Guarantor
Security Agreement, incorporated by
reference to Exhibit 10(X) on Form
S-4, filed January 10, 2001 (File No.
333-53470)

(T) Promissory Note dated December 20,
2000 from Seven Seas Petroleum Inc., a
Yukon Territory, Canada corporation,
and Stillwater National Bank and Trust
Company, N.A., incorporated by
reference to Exhibit 10(Y) on Form
S-4, filed January 10, 2001 (File No.
333-53470)

(U) Stock Pledge Agreement by Seven Seas
Petroleum Corporation, a Yukon
Territory, Canada corporation, Seven
Seas Petroleum Holdings Inc., a Cayman
Island corporation, and Seven Seas
Petroleum Columbia Inc., a Cayman
Islands corporation, in favor of
Stillwater National Bank and Trust
Company, N.A., incorporated by
reference to Exhibit 10(Z) on Form
S-4, filed January 10, 2001 (File No.
333-53470)

(V) Construction Contract dated December
27, 2000 between Seven Seas Petroleum
Corporation Inc., a Yukon Territory,
Canada corporation, and Cosacol Ltd.,
incorporated by reference to Exhibit
10(AA) on Form S-4, filed January 10,
2001 (File No. 333-53470)

(23) Consent of experts and counsel

*(A) Consent of Arthur Andersen LLP

(24) Power of Attorney (included in
signature page)

- ----------

* Filed herewith.

** Management contract, compensatory plan or agreement.

(b) Consolidated Financial Statement Schedules

All schedules are omitted as the required information is inapplicable or the
information is presented in the financial statements or notes thereto.

(b) Reports on Form 8-K

None

56
57

SIGNATURES

Pursuant to the requirements of the Securities and Exchange Act of 1934,
Seven Seas has duly caused this report to be signed on its behalf as of the 30th
day of March 2001 by the undersigned, thereunto duly authorized. SEVEN SEAS
PETROLEUM INC.

By: /s/ ROBERT A. HEFNER III
------------------------------
Robert A. Hefner III
Chief Executive Officer
(Principal Executive Officer)

By: /s/ RONALD A. LEFAIVE
------------------------------
Ronald A. Lefaive
Chief Financial Officer
(Principal Financial Officer)

The undersigned officers and directors of Seven Seas, hereby severally
constitute and appoint Robert A. Hefner III and Larry A. Ray, and each of them,
severally, his true and lawful attorneys-in-fact with full power to them and
each of them to sign for him, and in his name as officer or director, or both,
of Seven Seas, the Annual Report on Form 10-K for the fiscal year ended December
31, 2000 (and any and all amendments thereto), granting unto said
attorneys-in-fact and agents, and each of them, full power and authority to do
and to perform each and every act and thing requisite and necessary to be done
in and about the premises, as fully to all intents and purposes as he might or
could do in person, hereby ratifying and confirming all that said
attorneys-in-fact and agents, or any of them, may lawfully do or cause to be
done by virtue hereof.

Pursuant to the requirements of the Securities and Exchange Act of 1934,
this report has been signed as of the 30th day of March 2001 by the following
persons in their capacity as directors of the Registrant.

/s/ ROBERT A. HEFNER III Chairman and Chief Executive Officer
----------------------------
Robert A. Hefner III

/s/ LARRY A. RAY President, Chief Operating Officer, Corporate
---------------------------- Secretary and Director
Larry A. Ray

/s/ R. RANDOLPH DEVENING Director
----------------------------
R. Randolph Devening

/s/ BRIAN EGOLF Director
----------------------------
Brian Egolf

/s/ GARY F. FULLER Director
----------------------------
Gary F. Fuller

/s/ ROBERT B. PANERO Director
----------------------------
Robert B. Panero

/s/ DR. JAMES R. SCHLESINGER Director
----------------------------
Dr. James R. Schlesinger

57
58

INDEX TO EXHIBITS

EXHIBIT
NUMBER DESCRIPTION
------- -----------

(3) Articles of Incorporation and By-laws

(A)* Certificate of Continuance to the
Cayman Islands

(B)* Memorandum of Association

(C)* Articles of Association

(4) Instruments defining the rights of
security holders, including indentures

(10) Material Contracts

(F) Amended 1996 Stock Option Plan,
incorporated by reference to Exhibit
10(M) in Registration on Form 10 filed
April 30, 1997 (File No. 000-22483)

(G) Form of Incentive Stock Option
Agreement, incorporated by reference
to Exhibit 10(N) in Registration on
Form 10 filed April 30, 1997 (File No.
000-22483)

(H) Form of Directors' Stock Option
Agreement, incorporated by reference
to Exhibit 10(O) in Registration on
Form 10 filed April 30, 1997 (File No.
000-22483)

(I)** Form of Employment Agreement between
Seven Seas Petroleum Inc., a Yukon
Territory, Canada corporation, and
Larry A. Ray,

58
59

incorporated by reference to Exhibit
10(R) in Registration on Amendment No.
1 to Form 10, filed September 15, 1997
(File No. 000-22483)

(K) 1997 Stock Option Plan, incorporated
by reference to Exhibit 10(BB) in
Registration on Amendment No. 1 to
Form 10 filed September 15, 1997 (File
No. 000-22483)

(O)** Severance Agreement with Herbert C.
Williamson III, incorporated by
reference to Exhibit 10(W) on Form
10-K for the year ended December 31,
1999 (File No. 001-13771)

(P)** Severance Agreement with William W.
Daily, incorporated by reference to
Exhibit 10(X) on Form 10-K for the
year ended December 31, 1999 (File No.
001-13771)

(Q) Memorandum of Understanding with
Empresa Colombiana de Petroleos,
incorporated by reference to Exhibit
10(Y) on Form 10-K for the year ended
December 31, 1999 (File No. 001-13771)

(R) Global Operating License, incorporated
by reference to Exhibit 10(W) on Form
S-4, filed January 10, 2001 (File No.
333-53470)

(23) Consent of experts and counsel

*(A) Consent of Arthur Andersen LLP

(24) Power of Attorney (included in
signature page)

- ----------

* Filed herewith.

** Management contract, compensatory plan or agreement.